10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☑	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934		☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the fiscal year ended	December 31, 2019		For the transition period from                to

Commission File Number 1-9210

Occidental Petroleum Corporation

(Exact name of registrant as specified in its charter)

State or other jurisdiction of incorporation or organization	Delaware
I.R.S. Employer Identification No.	95-4035997
Address of principal executive offices	5 Greenway Plaza, Suite 110		Houston,	Texas
Zip Code	77046
Registrant’s telephone number, including area code	(713)	215-7000

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

Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, $0.20 par value	OXY	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 ☑ 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. Yes ☐   No  ☑

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 ☑   No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).       Yes ☑   No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	☑	Accelerated Filer	☐	Emerging Growth Company	☐
Non-Accelerated Filer	☐	Smaller Reporting Company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐   No  ☑

The aggregate market value of the registrant’s Common Stock held by nonaffiliates of the registrant was approximately $45.0 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $50.28 per share of Common Stock on June 28, 2019. 

At January 31, 2020, there were 895,224,961 shares of Common Stock outstanding, par value $0.20 per share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement, relating to its 2020 Annual Meeting of Stockholders, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS		PAGE
Part I
Items 1 and 2.	Business and Properties	2
	General	2
	Employees	2
	Available Information	2
	Oil and Gas Operations	3
	Chemical Operations	4
	Marketing and Midstream Operations	5
	Environmental Regulation	5
Item 1A.	Risk Factors	6
Item 1B.	Unresolved Staff Comments	13
Item 3.	Legal Proceedings	13
Item 4.	Mine Safety Disclosures	13
	Information About Our Executive Officers	14
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	15
Item 6.	Selected Financial Data	17
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)	18
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	125
Item 9A.	Controls and Procedures	125
Item 9B.	Other Information	125
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	126
Item 11.	Executive Compensation	126
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	126
Item 13.	Certain Relationships and Related Transactions and Director Independence	126
Item 14.	Principal Accounting Fees and Services	127
Part IV
Item 15.	Exhibits and Financial Statement Schedules	127
Item 16.	Form 10-K Summary	130

BUSINESS AND PROPERTIES

Part I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

In this report, “Occidental” means Occidental Petroleum Corporation, a Delaware corporation (OPC) incorporated in 1986, or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental conducts its operations through its various subsidiaries and affiliates. Occidental’s executive offices are located at 5 Greenway Plaza, Suite 110, Houston, Texas 77046; telephone (713) 215-7000.

On August 8, 2019, pursuant to the Agreement and Plan of Merger, dated as of May 9, 2019, among Occidental, Baseball Merger Sub 1, Inc., a Delaware corporation and an indirect, wholly owned subsidiary of Occidental (Merger Subsidiary), and Anadarko Petroleum Corporation (Anadarko), Occidental acquired all of the outstanding shares of Anadarko through a transaction in which Merger Subsidiary merged with and into Anadarko (the Acquisition), with Anadarko continuing as the surviving entity and as an indirect, wholly owned subsidiary of Occidental.

GENERAL

Occidental’s principal businesses consist of three reporting segments: oil and gas, chemical, and marketing and midstream. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The marketing and midstream segment purchases, markets, gathers, processes, transports and stores oil, condensate, NGL, natural gas, carbon dioxide (CO₂) and power. It also trades around its assets, including transportation and storage capacity, and invests in entities that conduct similar activities such as Western Midstream Partners, L.P. (WES).

The marketing and midstream segment also includes Oxy Low Carbon Ventures (OLCV). OLCV seeks to capitalize on Occidental’s enhanced oil recovery (EOR) leadership by developing carbon capture, utilization and storage projects that source anthropogenic CO₂ and promote innovative technologies that drive cost efficiencies and economically grow Occidental’s business while reducing emissions.

For further information regarding Occidental’s segments, geographic areas of operation and current developments, see the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) section of this report and Note 18 - Industry Segments and Geographic Areas in the Notes to Consolidated Financial Statements.

EMPLOYEES

Occidental employed approximately 14,400 people at December 31, 2019, which included approximately 1,000 employees who have been seconded to WES. Occidental has 10,000 employees located in the United States. Occidental employed approximately 10,400 people in the oil and gas and marketing and midstream segments and 3,000 people in the chemical segment. An additional 1,000 people were employed in administrative and corporate functions. Approximately 500 U.S.-based employees and 900 international-based employees are represented by labor unions.

AVAILABLE INFORMATION

Occidental’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports are available free of charge on its website, www.oxy.com, as soon as reasonably practicable after Occidental electronically files the material with, or furnishes it to, the Securities and Exchange Commission (SEC). In addition, copies of our annual report will be made available, free of charge, upon written request.

Information contained on Occidental’s website is not part of this report or any other filings with the SEC.

2 OXY 2019 FORM 10-K

BUSINESS AND PROPERTIES

OIL AND GAS OPERATIONS

GENERAL

Occidental’s oil and gas assets are located in some of the world’s highest-margin basins and are characterized by an advantaged mix of short- and long-cycle high-return development opportunities. Occidental conducts its ongoing exploration and production activities in the United States, the Middle East and Latin America. Within the United States, Occidental has operations in Texas, New Mexico, Colorado, Wyoming and Utah, as well as offshore operations in the Gulf of Mexico. Internationally, Occidental conducts operations in Oman, United Arab Emirates (UAE), Qatar and Colombia. Refer to the Supplemental Oil and Gas Information - Oil and Gas Acreage under Item 8 of this Form 10-K for further disclosure of Occidental’s holdings of developed and undeveloped oil and gas acreage.

In connection with the Acquisition, Occidental agreed to sell to TOTAL S.A. (Total) all of the assets, liabilities, businesses and operations of Anadarko’s operations in Algeria, Ghana, Mozambique and South Africa (collectively, the Africa Assets). Occidental completed the sale of Mozambique LNG assets for approximately $4.2 billion in September 2019. The remaining Africa Assets are classified as held-for-sale and not considered part of Occidental’s ongoing international operations as of December 31, 2019. In January 2020, Occidental completed the sale of South Africa assets to Total. The closing of the sale of the remaining Africa Assets is conditioned on the receipt of required regulatory and government approvals, as well as other customary closing conditions.

COMPETITION

As a producer of oil, condensate, NGL and natural gas, Occidental competes with numerous other domestic and international public, private and government producers. Oil, NGL and natural gas are sensitive to prevailing global and local, current and anticipated market conditions. Occidental competes for capacity and infrastructure for the gathering, processing, transportation, storage and delivery of its products, which are sold at current market prices or on a forward basis to refiners, end users and other market participants. Occidental’s competitive strategy relies on increasing production through developing conventional and unconventional fields, utilizing primary and EOR techniques and strategic acquisitions in areas where Occidental has a competitive advantage as a result of its successful operations or investments in shared infrastructure. Occidental also competes to develop and produce its worldwide oil and gas reserves safely and cost-effectively, maintain a skilled workforce and obtain quality services.

PROVED RESERVES AND SALES VOLUMES

The table below shows Occidental’s year-end oil, NGL and natural gas proved reserves, including reserves acquired in the Acquisition, but excluding reserves related to the Africa Assets. Year-to-date sales volumes exclude Anadarko sales prior to the date of the Acquisition and all sales related to the Africa Assets. See “MD&A — Oil and Gas Segment,” and the information under the caption “Supplemental Oil and Gas Information” for details regarding Occidental’s proved reserves, the reserves estimation process, sales and production volumes, production costs and other reserves-related data.

COMPARATIVE OIL AND GAS PROVED RESERVES AND SALES VOLUMES

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

	2019					2018					2017
	Oil	NGL	Gas	BOE	(a)	Oil	NGL	Gas	BOE	(a)	Oil	NGL	Gas	BOE	(a)
Proved Reserves (b)
United States	1,570	540	4,128	2,798		1,186	284	1,445	1,711		1,107	247	1,205	1,555
International (c)	400	200	2,572	1,029		397	202	2,650	1,041		408	198	2,626	1,043
Total	1,970	740	6,700	3,827		1,583	486	4,095	2,752		1,515	445	3,831	2,598
Sales Volumes
United States	155	52	326	261		91	25	119	136		73	20	108	111
International (c)	56	12	204	102		62	11	189	104		66	11	188	109
Total	211	64	530	363		153	36	308	240		139	31	296	220

^(a)  Natural gas volumes are converted to barrels of oil equivalence (BOE) at six thousand cubic feet (Mcf) of gas per one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. 

^(b)  The detailed proved reserves information presented in accordance with Item 1202(a)(2) to Regulation S-K under the Securities Exchange Act of 1934 (Exchange Act) is provided under the heading “Supplemental Oil and Gas Information”. Proved reserves are stated on a net basis after applicable royalties.

^(c)  Excluded reserves of 125 MMBOE and sales of 12 MMBOE related to the Africa Assets.

OXY 2019 FORM 10-K 3

BUSINESS AND PROPERTIES

CHEMICAL OPERATIONS

GENERAL

OxyChem owns and operates manufacturing plants at 22 domestic sites in Alabama, Georgia, Illinois, Kansas, Louisiana, Michigan, New Jersey, New York, Ohio, Tennessee and Texas and at two international sites in Canada and Chile.

COMPETITION

OxyChem competes with numerous other domestic and international chemical producers. OxyChem’s market position was first or second in the United States in 2019 for the principal basic chemical products it manufactures and markets as well as for vinyl chloride monomer (VCM). OxyChem ranks in the top three producers of polyvinyl 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	3.4 million tons
Caustic soda	Pulp, paper and aluminum production	3.5 million tons
Chlorinated organics	Refrigerants(a), silicones and pharmaceuticals	1.0 billion pounds
Potassium chemicals	Fertilizers, batteries, soaps, detergents and specialty glass	0.4 million tons
EDC	Raw material for 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 PVC	6.2 billion pounds
PVC	Piping, building materials and automotive and medical products	3.7 billion pounds
Ethylene	Raw material for VCM	1.2 billion pounds (b)

^(a)  Includes 4CPe, a raw material used in making next-generation, climate-friendly refrigerants with low global-warming and zero ozone-depletion potential.

^(b)  Amount is gross production capacity for 50/50 joint venture with Orbia (formerly Mexichem).

4 OXY 2019 FORM 10-K

BUSINESS AND PROPERTIES

MARKETING AND MIDSTREAM OPERATIONS

GENERAL

Occidental’s marketing and midstream operations primarily support and enhance its oil and gas and chemical businesses and also provide similar services for third parties. The marketing and midstream segment strives to maximize realized value by optimizing the use of its gathering, processing, transportation, storage and terminal commitments and by providing access to domestic and international markets. To generate returns, the segment evaluates opportunities across the value chain and uses its assets to provide services to Occidental subsidiaries, as well as third parties. The marketing and midstream segment operates gathering systems, gas plants, co-generation facilities and storage facilities and invests in entities that conduct similar activities. Also included in the marketing and midstream segment is OLCV.

Included in the marketing and midstream segment is Occidental’s equity method investment in WES. WES owns gathering systems, plants and pipelines and earns revenue from fee-based and service-based contracts with Occidental and third parties.

COMPETITION

Occidental’s marketing and midstream businesses operate in competitive and highly regulated markets. From the date of the Acquisition to December 31, 2019, WES was a consolidated subsidiary in Occidental’s financial statements. Occidental’s marketing business competes with other market participants on exchange platforms and through other bilateral transactions with direct counterparties.

Occidental’s marketing and midstream operations are conducted in the locations described below as of December 31, 2019:

Location	Description	Capacity
Gas Plants
Texas, New Mexico and Colorado	Occidental and third-party-operated natural gas gathering, compression and processing systems, and CO2 processing and capturing	2.7 Bcf per day
Rocky Mountains, Pennsylvania, Texas and New Mexico	Equity investment in WES - gas processing facilities	5.7 Bcf per day
UAE	Natural gas processing facilities for Al Hosn Gas	1.3 Bcf of natural gas per day
Pipelines and Gathering Systems
Texas, New Mexico and Colorado	CO2 fields and pipeline systems transporting CO2 to oil and gas producing locations	2.8 Bcf per day
Qatar, UAE and Oman	Equity investment in the Dolphin Energy Ltd natural gas pipeline	3.2 Bcf of natural gas per day
United States	Equity investment in WES involved in gathering and transportation	15,819 miles of pipeline(a)
Power Generation
Texas and Louisiana	Occidental-operated power and steam generation facilities	1,218 megawatts of electricity and 1.6 million pounds of steam per hour

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

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.”

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RISK FACTORS

ITEM 1A. RISK FACTORS

Risks related to Occidental’s business and operations

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

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

Prices for oil, natural gas and NGL fluctuate widely. Historically, the markets for oil, natural gas and NGL have been volatile and may continue to be volatile in the future. If the prices of oil, natural gas, or NGL continue to be volatile or decline, Occidental’s operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected. Prices are set by global and local market forces which are not in Occidental’s control. These factors include, among others:

Ø Worldwide and domestic supplies of, and demand for, oil, natural gas, NGL and refined products;

Ø The cost of exploring for, developing, producing, refining and marketing oil, natural gas, NGL and refined products;

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

Ø Changes in weather patterns and climate;

Ø The impacts of the members of OPEC and other non-OPEC member-producing nations that may agree to and maintain production levels;

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

Ø The price and availability of alternative and competing fuels;

Ø Technological advances affecting energy consumption and supply;

Ø Domestic and foreign governmental regulations and taxes;

Ø Shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas and NGL;

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

Ø The impact and uncertainty of world health events;

Ø Volatility in commodity futures markets;

Ø The effect of energy conservation efforts; and

Ø Global inventory levels and general economic conditions.

The long-term effects of these and other conditions on the prices of oil, natural gas, NGL and refined products are uncertain, and there can be no assurance that the demand or pricing for Occidental’s products will follow historic patterns or recover meaningfully in the near term. Prolonged or substantial decline, or sustained market uncertainty, in these commodity prices may have the following effects on Occidental’s business:

Ø Adversely affect Occidental’s financial condition, liquidity, ability to reduce debt, pay dividends, finance planned capital expenditures, ability to repurchase shares and results of operations;

Ø Reduce the amount of oil, natural gas and NGLs that Occidental can produce economically;

Ø Cause Occidental to delay or postpone some of its capital projects;

Ø Reduce Occidental’s revenues, operating income or cash flows;

Ø Reduce the amounts of Occidental’s estimated proved oil, natural gas and NGL reserves;

Ø Reduce the carrying value of Occidental’s oil and natural gas properties due to recognizing impairments of proved properties, unproved properties and exploration assets;

Ø Reduce the standardized measure of discounted future net cash flows relating to oil, natural gas and NGL reserves;

Ø Limit Occidental’s access to, or increase the cost of, sources of capital such as equity and long-term debt; and

Ø Adversely affect the ability of Occidental’s partners to fund their working interest capital requirements.

Generally, Occidental’s historical practice has been to remain exposed to the market prices of commodities. In 2019, management elected to hedge a portion of Occidental’s expected 2020 oil production to enhance cash flow stability following the Acquisition. In the future, management may elect to hedge some of the risk of oil, natural gas and NGL price fluctuations. Past or future commodity price risk management activities may prevent us from fully benefiting from price increases and may expose us to regulatory and other risks.

The prices obtained for Occidental’s chemical products correlate 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.

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RISK FACTORS

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

Oil, natural gas and NGL exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil, natural gas and NGL production. In its development and exploration activities, Occidental bears the risks of:

Ø Equipment failures;

Ø Construction delays;

Ø Escalating costs or competition for services, materials, supplies or labor;

Ø Property or border disputes;

Ø Disappointing drilling results or reservoir performance;

Ø Title problems and other associated risks that may affect its ability to profitably grow production, replace reserves and achieve its targeted returns;

Ø Actions by third-party operators of our properties;

Ø Delays and costs of drilling wells on lands subject to complex development terms and circumstances; and

Ø Oil, natural gas or NGL gathering, transportation and processing availability, restrictions or limitations.

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 actions and decisions of many federal, state, local and foreign governments and political interests. As a result, Occidental faces risks of:

Ø New or amended laws and regulations, or new or different applications or interpretations of existing laws and regulations, including those related to drilling, manufacturing or production processes (including well stimulation techniques such as hydraulic fracturing and acidization), pipelines, 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, the manufacturing of chemicals, asset integrity management, the marketing or export of commodities, 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. In addition, violation of certain governmental laws and regulations may result in strict, joint and several liability and the imposition of significant civil and criminal fines and penalties;

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

Ø Development delays and cost overruns due to approval delays for, or denial of, drilling, construction, environmental and other regulatory approvals, permits and authorizations.

As an example of local governmental actions, some counties in Colorado have amended their land use regulations to impose new requirements on oil and gas development while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Further, voters in Colorado have proposed or advanced ballot initiatives restricting or banning oil and gas development in Colorado. In the event that these ballot initiatives are adopted or the county-level regulations are implemented in areas where we conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development or production activities.

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 affected by political instability, nationalizations, corruption, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions. Exposure to such risks may increase if a greater percentage of Occidental’s future oil and gas production or revenue comes from international sources.

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

Results of operations, reserves replacement and growth in oil and gas production depend, in part, on Occidental’s ability to profitably acquire additional reserves. Occidental has many competitors (including national oil companies), some of which: (i) are larger and better funded; (ii) may be willing to accept greater risks; (iii) have greater access to capital; (iv) have substantially larger staffs; or (v) have special competencies. Competition for reserves may make it more difficult to find attractive investment opportunities or require delay of reserve replacement efforts. Further, during periods of low product prices, any cash conservation efforts may delay production growth and reserve replacement efforts. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Our failure to acquire properties, grow production, replace reserves and attract and retain qualified personnel could have a material adverse effect on our cash flows and results of operations.

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RISK FACTORS

In addition, Occidental’s acquisition activities carry risks that it may: (i) not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances, such as declines in oil, NGL, and natural gas 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) be subject to 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 oil and natural gas prices, future operating costs and capital expenditures, workover and remedial costs, assumed effects of regulation by governmental agencies, the quantity, quality and interpretation of relevant data, taxes and availability of funds. The procedures and 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, expenditures, oil, NGL and natural gas prices and taxes 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 and costs used for purposes of estimating future discounted net cash flows from proved reserves. Also, actual future net cash flows may differ from these discounted net cash flows due to the amount and timing of actual production, availability of financing for capital expenditures necessary to develop our undeveloped reserves, supply and demand for oil, NGL and natural gas, increases or decreases in consumption of oil, natural gas and NGL and changes in governmental regulations or taxation.

Climate change and further regulation of greenhouse gas emissions may adversely affect Occidental’s operations or results.

Continuing political and social attention to the issue of 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. In December 2009, the Environmental Protection Agency (EPA) determined that emissions of carbon dioxide, methane and other greenhouse gases endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (CAA). For example, the EPA issued rules restricting methane emissions from hydraulically fractured and refractured gas wells, compressors, pneumatic controls, storage vessels, and natural gas processing plants. In addition, in August 2019, the EPA issued the Affordable Clean Energy rule that designates heat rate improvement, or efficiency improvement, as the best system of emissions reduction for carbon dioxide from existing coal-fired electric utility generating units.

In the absence of federal legislation to significantly reduce emissions of greenhouse gases to date, many state governments have established rules aimed at reducing greenhouse gas emissions, including greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, including refineries and natural gas processing plants, to acquire and surrender emission allowances. In the future, the United States may also choose to adhere to international agreements targeting greenhouse gas reductions. These and other government 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, pay carbon taxes, or comply with new regulatory or reporting requirements, or they could promote the use of alternative sources of energy and thereby decrease demand for oil, natural gas, NGL and other products that Occidental’s businesses produce. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas, NGL and other products produced by Occidental’s businesses and lower the value of its reserves. Consequently, government actions designed to reduce emissions of greenhouse gases could have an adverse effect on Occidental’s business, financial condition, results of operations, cash flows and reserves.

It is difficult to predict the timing and certainty of such government actions and their ultimate effect on Occidental, which could depend on, among other things, the type and extent of greenhouse 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 its oil, natural gas, NGL and other products.

There also have been efforts in the investment community, including investment advisers and certain sovereign wealth, pension and endowment funds, as well as other stakeholders, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Such initiatives could cause the market value of our securities to decrease, our cost of capital to

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RISK FACTORS

increase and adversely affect our reputation. Finally, increasing attention to climate change risks has resulted in an increased possibility of governmental investigations and additional private litigation against Occidental without regard to causation or our contribution to the asserted damage, which could increase our costs or otherwise adversely affect our business. Occidental has been named in certain private litigation relating to these matters.

Occidental’s businesses may experience catastrophic events.

The occurrence of events such as hurricanes, floods, droughts, earthquakes or other acts of nature, well blowouts, pandemics, fires, explosions, pipeline ruptures, chemical releases, oil releases, including maritime releases, releases into navigable waters, and groundwater contamination, material or mechanical failure, industrial accidents, physical attacks, abnormally pressured or structured formations and other events that cause operations to cease or be curtailed may negatively affect Occidental’s businesses and the communities in which it operates. Coastal operations are particularly susceptible to disruption from extreme weather events. Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

Ø Damage to and destruction of property and equipment;

Ø Damage to natural resources;

Ø Pollution and other environmental damage, including spillage or mishandling of recovered chemicals or fluids;

Ø Regulatory investigations and penalties;

Ø Loss of well location, acreage, expected production and related reserves;

Ø Suspension or delay of our operations;

Ø Substantial liability claims; and

Ø Repair and remediation costs.

Third-party insurance may not provide adequate coverage or Occidental may be self-insured with respect to the related losses. In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities for environmental matters for which we do not have insurance coverage, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

Occidental uses CO₂ for its enhanced oil recovery (EOR) operations, and its production from these operations may decline if Occidental is not able to obtain sufficient amounts of CO₂.

Occidental’s CO₂  EOR operations are critical to Occidental’s long-term strategy. Oil production from Occidental’s EOR projects depends largely on having access to sufficient amounts of naturally occurring or anthropogenic CO₂. Occidental’s ability to produce oil from its EOR projects would be hindered if the supply of CO₂ was limited due to, among other things, problems with current CO₂ producing wells and facilities, including compression equipment, catastrophic pipeline failure or the ability to economically purchase naturally occurring or anthropogenic CO₂. This could have a material adverse effect on Occidental’s financial condition, results of operations or cash flows. Future oil production from its EOR operations is dependent on the timing, volumes and location of CO₂ injections and, in particular, Occidental’s ability to obtain sufficient volumes of CO₂. Market conditions may cause the delay or cancellation of the development of naturally occurring CO₂ sources or construction of plants that produce anthropogenic CO₂ as a byproduct that can be purchased, thus limiting the amount of CO₂ available for use in Occidental’s EOR operations.

Occidental is exposed to cyber-related risks.

The oil and gas industry is increasingly dependent on digital and industrial control technologies to conduct certain exploration, development and production activities. Occidental relies on digital and industrial control systems, related infrastructure, technologies and networks to run its business and to control and manage its oil and gas, chemicals, marketing and pipeline operations. Use of the internet, cloud services, mobile communication systems and other public networks exposes Occidental’s business and that of other third parties with whom Occidental does business to cyber-attacks. Cyber-attacks on businesses have escalated in recent years.

Information and industrial control technology system failures, network disruptions and breaches of data security could disrupt our operations by causing delays, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of company, partner, customer or employee information or could damage our reputation. A cyber-attack involving our information or industrial control systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including but not limited to, the following:

Ø Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and natural gas resources;

Ø Data corruption, communication or systems interruption or other operational disruption during drilling activities could result in delays and failure to reach the intended target or cause a drilling incident;

OXY 2019 FORM 10-K 9

RISK FACTORS

Ø Data corruption, communication or systems interruption or operational disruptions of production-related infrastructure could result in a loss of production or accidental discharge;

Ø A cyber-attack on our chemical operations could result in a disruption of the manufacturing and marketing of our products or a potential environmental hazard;

Ø A cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt our construction and development projects;

Ø A cyber-attack on third-party gathering, pipeline, processing, or other infrastructure systems could delay or prevent us from transporting, processing and marketing our production;

Ø A cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities;

Ø A cyber-attack that halts activities at a power generation facility or refinery using natural gas as feedstock could have a significant impact on the natural gas market;

Ø A cyber-attack on a communications network or power grid could cause operational disruption;

Ø A cyber-attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;

Ø A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and

Ø A cyber-attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

Even though Occidental has implemented controls and multiple layers of security to mitigate the risks of a cyber-attack that it believes are reasonable, there can be no assurance that such cyber security measures will be sufficient to prevent security breaches of its systems from occurring, and if a breach occurs, it may remain undetected for an extended period of time. Further, Occidental has no control over the comparable systems of the third parties with whom it does business. While Occidental has experienced cyber-attacks in the past, Occidental has not suffered any material losses. However, if in the future Occidental’s cyber security measures are compromised or prove insufficient, the potential consequences to Occidental’s businesses and the communities in which it operates could be significant. As cyber-attacks continue to evolve in magnitude and sophistication, Occidental may be required to expend additional resources in order to continue to enhance Occidental’s cyber security measures and to investigate and remediate any digital and operational systems, related infrastructure, technologies and network security vulnerabilities, which would increase our costs. A system failure or data security breach, or a series of such failures or breaches, could have a material adverse effect on our financial condition, results of operations or cash flows.

Occidental’s oil and gas reserve additions may not continue at the same rate and a failure to replace reserves may negatively affect Occidental’s business.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless Occidental conducts successful exploration or development activities, acquires properties containing proved reserves, or both, proved reserves will generally decline and negatively impact our business. The value of our securities and our ability to raise capital will be adversely impacted if we are not able to replace reserves that are depleted by production or replace our declining production with new production. Management expects improved recovery, extensions and discoveries to continue as main sources for reserve additions but factors such as geology, government regulations and permits, the effectiveness of development plans and the ability to make the necessary capital investments or acquire capital are partially or fully outside management’s control and could cause results to differ materially from expectations.

Occidental’s commodity-price risk management may prevent us from fully benefiting from price increases and may expose us to regulatory and other risks.

To the extent that we engage in activities to protect Occidental’s cash flows from commodity-price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, Occidental’s commodity-price risk management may expose us to the risk of financial loss in certain circumstances, including instances in which the following occur:

Ø Occidental’s production is less than the notional volume;

Ø The counterparties to Occidental’s hedging or other price risk management contracts fail to perform under those arrangements; or

Ø A sudden, unexpected event materially impacts oil, natural gas or NGL prices.

10 OXY 2019 FORM 10-K

RISK FACTORS

Occidental’s operations and financial results could be significantly negatively impacted by its offshore operations.

Occidental is vulnerable to risks associated with our offshore operations that could negatively impact our operations and financial results. Occidental conducts offshore operations in the Gulf of Mexico and Ghana. Occidental’s operations and financial results could be significantly impacted by conditions in some of these areas and are also vulnerable to certain unique risks associated with operating offshore, including those relating to the following:

Ø Hurricanes and other adverse weather conditions;

Ø Geological complexities and water depths associated with such operations;

Ø Limited number of partners available to participate in projects;

Ø Oilfield service costs and availability;

Ø Compliance with environmental, safety, and other laws and regulations;

Ø Terrorist attacks or piracy;

Ø Remediation and other costs and regulatory changes resulting from oil spills or releases of hazardous materials;

Ø Failure of equipment or facilities; and

Ø Response capabilities for personnel, equipment, or environmental incidents.

In addition, Occidental conducts some of its exploration in deep waters (greater than 1,000 feet) where operations, support services, and decommissioning activities are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico, as well as international deepwater locations, lack the physical and oilfield service infrastructure present in shallower waters. As a result, deepwater operations may require significant time between a discovery and the time that Occidental can market its production, thereby increasing the risk involved with these operations.

Additional domestic and international deepwater drilling laws, regulations and other restrictions, delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and other offshore-related developments may have a material adverse effect on Occidental’s business, financial condition or results of operations.

The Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. In addition, these governmental agencies are continuing to evaluate, develop and implement new, more restrictive regulatory requirements, which could result in additional costs, delays, restrictions or obligations with respect to oil exploration and production operations conducted offshore. For example, the BOEM has considered, and may adopt, supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines and other facilities, which may be material. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.

Occidental’s indebtedness may make it more vulnerable to economic downturns and adverse developments in its business. A downgrade in Occidental’s credit ratings or future increases in interest rates may negatively impact Occidental’s cost of and ability to access the capital markets.

Occidental incurred indebtedness and other payment obligations in connection with the Acquisition. Occidental’s higher level of indebtedness could increase Occidental’s vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in its business and/or limit Occidental’s flexibility in planning for or reacting to changes in its business and the industries in which it operates. From time to time, Occidental has relied on access to the capital markets for funding, including in connection with the Acquisition. There can be no assurance that additional debt or equity financing will be available to Occidental in the future on acceptable terms, or at all. Occidental’s ability to obtain additional financing or refinancing will be subject to a number of factors, including general economic and market conditions, Occidental’s performance, investor sentiment and its existing debt compliance requirements. If Occidental is unable to generate sufficient funds from its operations to satisfy its capital requirements, including its existing debt obligations, or to raise additional capital on acceptable terms, Occidental’s business could be adversely affected. In addition, a downgrade in the credit rating of Occidental could negatively impact its cost of and ability to access capital and to effectively execute aspects of its strategy, and may require Occidental to provide collateral, letters of credit, or other forms of security under certain contractual agreements, which would increase Occidental’s operating costs. As a result, a downgrade below investment grade in Occidental’s credit ratings could have a material adverse impact on Occidental’s financial condition, operating results, or liquidity.

Further, a portion of Occidental’s indebtedness bears interest at fluctuating interest rates, some of which is tied to the London Interbank Offered Rate (“LIBOR”). LIBOR tends to fluctuate based on general interest rates, rates set by the Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. In July 2017, the United Kingdom Financial Conduct Authority, which regulates LIBOR, announced that it intends to stop compelling banks

OXY 2019 FORM 10-K 11

RISK FACTORS

to submit rates for the calculation of LIBOR after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. These reforms and other pressures may cause LIBOR to disappear entirely or to perform differently than in the past. The consequences of these developments cannot be entirely predicted, but may include an increase in the cost of Occidental’s variable rate indebtedness, including floating rate notes and interest rate swaps, which may have an adverse effect on Occidental’s financial condition, operating results or cash flows.

Risks related to Occidental’s Acquisition of Anadarko

Occidental may not be able to integrate Anadarko successfully, and many of the anticipated benefits of combining Occidental and Anadarko may not be realized.

Occidental acquired Anadarko with the expectation that the Acquisition will result in various benefits, including, among other things, operating efficiencies. Achieving those anticipated benefits is subject to a number of uncertainties, including whether Occidental can integrate the business of Anadarko in an efficient and effective manner. Occidental cannot ensure that those benefits will be realized as quickly as expected or at all. If Occidental does not achieve anticipated benefits, costs could increase, expected net income could decrease, the stock price could decline, and future business, financial condition, operating results and prospects could suffer.

The integration process could take longer than anticipated and involve unanticipated costs. Disruptions of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements could adversely affect the combined company. Occidental may also have difficulty addressing differences in corporate cultures and management philosophies and harmonizing other systems and business practices. Although Occidental expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will over time offset the substantial incremental transaction and Acquisition-related costs, Occidental may not achieve this net benefit in the near term, or at all.

Moreover, even if the integration of Anadarko is successful, the integration process places a significant burden on Occidental’s management and internal resources. The diversion of management’s attention away from day-to-day business concerns and any difficulties encountered in the integration process could adversely affect our financial condition, results of operations or cash flows.

Future results will be negatively impacted if Occidental does not effectively manage its expanded operations.

With completion of the Acquisition, the size of Occidental’s business has increased significantly. Occidental’s continued success depends, in part, upon its ability to manage this expanded business, which poses substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. Occidental cannot assure that it will be successful or that it will realize the expected operating efficiencies, cost savings and other benefits from the combination currently anticipated.

Anadarko’s Tronox settlement may not be deductible for income tax purposes, and Occidental may be required to repay the tax refund Anadarko received in 2016 related to the deduction of the Tronox settlement payment, which may have a material adverse effect on Occidental’s results of operations, liquidity and financial condition.

In April 2014, Anadarko and Kerr-McGee Corporation and certain of its subsidiaries (collectively, Kerr-McGee) entered into a settlement agreement for $5.15 billion, resolving all claims that were or could have been asserted in connection with the May 2009 lawsuit filed by Tronox against Anadarko and Kerr-McGee Corporation (and certain of its subsidiaries) in the U.S. Bankruptcy Court for the Southern District of New York. After the settlement became effective in January 2015, Anadarko paid $5.2 billion and deducted this payment on its 2015 federal income tax return. Due to the deduction, Anadarko had a net operating loss carryback for 2015, which resulted in a tentative tax refund of $881 million in 2016. Occidental’s consolidated financial statements include an uncertain tax position greater than the amount of the tentative tax refund received.

The IRS has audited Anadarko’s tax position regarding the deductibility of the payment and in September 2018 issued a statutory notice of deficiency rejecting Anadarko’s refund claim. Anadarko disagreed and filed a petition with the U.S. Tax Court to dispute the disallowance in November 2018. It is possible that Occidental may not ultimately succeed in defending this deduction. If the payment is ultimately determined not to be deductible, Occidental would be required to repay the tentative refund received plus interest totaling approximately $1.1 billion as of December 31, 2019, which could have a material adverse effect on our statement of operations, liquidity and consolidated balance sheets. This amount is not covered by insurance. For additional information on income taxes, see Note 11 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements.

12 OXY 2019 FORM 10-K

RISK FACTORS

Occidental may not be able to complete its planned divestitures of certain assets on favorable terms or at all.

Occidental announced a $15 billion divestiture program in connection with the Acquisition. The completion of these divestitures is subject to customary closing conditions, and certain of the divestitures are conditioned on the receipt of required government and regulatory approvals. Occidental may not be able to complete its planned divestitures on favorable terms, in a timely manner or at all. Any difficulties with respect to the completion of the planned divestitures could have a material adverse effect on Occidental’s business, financial condition, results of operations, cash flows and/or stock price. See Note 4 - Acquisitions, Dispositions and Other Transactions in the Notes to Consolidated Financial Statements in Part II Item 8 of this Form 10-K for information about the Total transaction.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

On July 17, 2019, an Occidental subsidiary received a draft consent agreement and final order from the EPA regarding alleged violations under the CAA and various sections of the EPA’s Chemical Accident Prevention Provisions at the Convent, Louisiana facility. The EPA’s order includes allegations associated with process reviews, procedures and recordkeeping. The EPA’s revised draft settlement proposal includes a civil penalty of $121,457. Occidental is currently negotiating a resolution of this matter with the EPA.

On September 13, 2019, an Occidental subsidiary received a draft consent agreement and final order from the EPA regarding alleged violations under the CAA and various sections of the EPA’s Chemical Accident Prevention Provisions at the Geismar, Louisiana facility. The EPA’s order includes allegations associated with operating procedures, inspections, contractor reviews, medical protocols in the emergency response plan, administrative updates and four historical on-site incidents. The EPA’s revised draft settlement proposal includes a civil penalty of $734,182. Occidental is currently negotiating a resolution of this matter with the EPA.

For information regarding legal proceedings, see the information under the caption “Lawsuits, Claims, Commitments and Contingencies” in the MD&A section of this report and in Note 11 - Lawsuits, Claims, Commitments and Contingencies in the Notes to Consolidated Financial Statements.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

OXY 2019 FORM 10-K 13

OTHER INFORMATION

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

Each executive officer holds his or her office from the date of election by the Board of Directors until the first board meeting held after the next Annual Meeting of Stockholders or until his or her removal or departure or a successor is duly elected, if earlier.

The following table sets forth the executive officers of Occidental as of February 27, 2020:

Name Current Title	Age at February 27, 2020	Positions with Occidental and Employment History
Marcia E. Backus Senior Vice President	65	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, 2013-2014; Vinson & Elkins: Partner, 1990-2013.
Oscar K. Brown Senior Vice President	49	Senior Vice President - Strategy, Business Development and Supply Chain since November 2018; Senior Vice President - Corporate Strategy and Development, 2017 - 2018; Senior Vice President - Business Development, 2016 - 2017; Bank of America Merrill Lynch: Managing Director and co-head of Americas Energy Investment Banking, 2010 - 2016.
Cedric W. Burgher Chief Financial Officer and Senior Vice President	59	Senior Vice President and Chief Financial Officer since May 2017; EOG Resources: Senior Vice President, Investor and Public Relations, 2014-2017; QR Energy L.P.: Chief Financial Officer, 2010-2014.
Christopher O. Champion Vice President	50	Vice President, Chief Accounting Officer and Controller since August 2019; Anadarko Petroleum Corporation: Senior Vice President, Chief Accounting Officer and Controller, 2017-2019; Vice President, Chief Accounting Officer and Controller 2015-2017; KPMG LLP: Audit Partner, 2003-2015.
Kenneth Dillon Senior Vice President	60	Senior Vice President since December 2016; President - International Oil and Gas Operations since June 2016; Senior Vice President - Operations and Major Projects, 2014-2016; Senior Vice President - Major Projects, 2012-2014.
Vicki Hollub President and Chief Executive Officer	60	President, Chief Executive Officer and Director since April 2016; President, Chief Operating Officer and Director, 2015-2016; Senior Executive Vice President and President, Oxy Oil and Gas, 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.
Edward A. “Sandy” Lowe Executive Vice President	68	Executive Vice President since 2015; Group Chairman - Middle East since 2016; Senior Vice President, 2008-2015; President - Oxy Oil & Gas International, 2009-2016.
Robert Palmer Senior Vice President	64	Senior Vice President since July 2017; President - Domestic Onshore Oil and Gas Operations, Oxy Oil and Gas since June 2019; Senior Vice President - Technical Support, 2017-2019; President and General Manager - Colombia, 2012-2017.
Glenn M. Vangolen Senior Vice President	61	Senior Vice President, Business Support since February 2015; Executive Vice President, Business Support, 2014-2015; Senior Vice President - Oxy Oil & Gas Middle East, 2010-2014.

14 OXY 2019 FORM 10-K

OTHER INFORMATION

Part II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET INFORMATION, HOLDERS AND DIVIDEND POLICY

Occidental’s common stock is listed and traded on the New York Stock Exchange under the ticker symbol “OXY.” The common stock was held by approximately 27,700 stockholders of record at January 31, 2020, which does not include beneficial owners for whom Cede and Co. or others act as nominees.

Occidental’s current annualized dividend rate of $3.16 per share has increased by over 500% since 2002. The declaration of future dividends is a business decision made by the Board of Directors from time to time, and will depend on Occidental’s financial condition and other factors deemed relevant by the Board.

SHARE REPURCHASE ACTIVITIES

Occidental’s share repurchase activities for the year ended December 31, 2019, 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 2019	2,690,000			$	66.94		2,690,000
Second Quarter 2019	—			$	—		—
Third Quarter 2019	—			$	—		—
Fourth Quarter 2019	—	(a)		$	—		—
Total 2019	2,690,000	(a)		$	66.94		2,690,000		44,206,787	(b)

^(a)  There were no purchases from the trustee of Occidental’s defined contribution savings plan in the fourth quarter of 2019.

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

OXY 2019 FORM 10-K 15

OTHER INFORMATION

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 includes Occidental, and with that of Occidental’s peer group over the five-year period ended December 31, 2019. The graph assumes that $100 was invested at the beginning of the five-year period shown in the graph below in: (i) Occidental common stock, (ii) the stock of the companies in the S&P 500, and (iii) each of the peer group companies’ common stock weighted by their relative market capitalization within the peer group, and that all dividends were reinvested. The cumulative total return of the peer group companies’ common stock includes the cumulative total return of Occidental’s common stock.

Occidental’s peer group consists of 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.

Fiscal Year Ended December 31	2014		2015		2016		2017		2018		2019
Occidental	$	100	$	87	$	96	$	104	$	91	$	65
Peer Group	$	100	$	83	$	104	$	107	$	95	$	103
S&P 500	$	100	$	101	$	113	$	138	$	132	$	174

The information provided in this Performance Graph shall not be deemed “soliciting material” or “filed” with the SEC 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.

16 OXY 2019 FORM 10-K

OTHER INFORMATION

ITEM 6. SELECTED FINANCIAL DATA

millions, except per-share amounts	2019 (a)			2018			2017			2016			2015
RESULTS OF OPERATIONS (b,c)
Net sales	$	20,393		$	17,824		$	12,508		$	10,090		$	12,480
Income (loss) from continuing operations	$	(507	)	$	4,131		$	1,311		$	(1,002	)	$	(8,146	)
Net income (loss) attributable to common stockholders	$	(985	)	$	4,131		$	1,311		$	(574	)	$	(7,829	)
Net income (loss) from continuing operations attributable to common stockholders - basic per common share	$	(1.20	)	$	5.40		$	1.71		$	(1.31	)	$	(10.64	)
Net income (loss) attributable to common stockholders - basic per common share	$	(1.22	)	$	5.40		$	1.71		$	(0.75	)	$	(10.23	)
Net income (loss) attributable to common stockholders - diluted per common share	$	(1.22	)	$	5.39		$	1.70		$	(0.75	)	$	(10.23	)
FINANCIAL POSITION (b)
Total assets	$	109,330		$	43,854		$	42,026		$	43,109		$	43,409
Long-term debt, net	$	38,537		$	10,201		$	9,328		$	9,819		$	6,855
Stockholders’ equity	$	34,232		$	21,330		$	20,572		$	21,497		$	24,350
MARKET CAPITALIZATION (d)	$	36,846		$	45,998		$	56,357		$	54,437		$	51,632
CASH FLOW FROM CONTINUING OPERATIONS (b,c)
Operating:
Cash flow from continuing operations	$	7,203		$	7,669		$	4,861		$	2,520		$	3,251
Investing:
Capital expenditures	$	(6,355	)	$	(4,975	)	$	(3,599	)	$	(2,717	)	$	(5,272	)
Payments for purchases of assets and businesses	$	(28,088	)	$	(928	)	$	(1,064	)	$	(2,044	)	$	(109	)
Sales of assets, net	$	6,143		$	2,824		$	1,403		$	302		$	819
Cash provided (used) by all other investing activities, net	$	(573	)	$	(127	)	$	181		$	(284	)	$	(858	)
Financing:
Cash dividends paid	$	(2,624	)	$	(2,374	)	$	(2,346	)	$	(2,309	)	$	(2,264	)
Purchases of treasury stock	$	(237	)	$	(1,248	)	$	(25	)	$	(22	)	$	(593	)
Proceeds from long-term debt, net - Occidental	$	21,557		$	978		$	—		$	4,203		$	1,478
Payment of long-term debt, net - Occidental	$	(6,959	)	$	(500	)	$	—		$	(2,710	)	$	—
Proceeds from issuance of common and preferred stock	$	10,028		$	33		$	28		$	36		$	37
Cash provided (used) by all other financing activities, net	$	431		$	9		$	—		$	—		$	—
DIVIDENDS PER COMMON SHARE	$	3.14		$	3.10		$	3.06		$	3.02		$	2.97
WEIGHTED-AVERAGE BASIC SHARES OUTSTANDING	810			762			765			764			766

^(a)  Summary financial information included the impact of the Acquisition, see Note 3 - The Acquisition in the Notes to Consolidated Financial Statements. Summary results of operations from the date of the Acquisition to December 31, 2019 included the results of WES, a previously consolidated subsidiary. The summary results of operations also included a loss as a result of no longer consolidating WES of approximately $1 billion. See Note 1 - Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

^(b)  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 charges affecting comparability.

^(c)  The 2019 results include results of operations and cash flows related to the Acquisition for the period beginning August 8, 2019 through December 31, 2019.

^(d)  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.

OXY 2019 FORM 10-K 17

MANAGEMENT’S DISCUSSION AND ANALYSIS

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.

INDEX	PAGE
Strategy	19
Oil and Gas Segment	19
Chemical Segment	30
Marketing and Midstream Segment	31
Segment Results of Operations and Items Affecting Comparability	33
Income Taxes	37
Consolidated Results of Operations	37
Liquidity and Capital Resources	40
Off-Balance Sheet Arrangements	42
Commitments and Obligations	42
Lawsuits, Claims, Commitments and Contingencies	43
Environmental Liabilities and Expenditures	44
Global Investments	46
Critical Accounting Policies and Estimates	46
Significant Accounting and Disclosure Changes	49
Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data	50

18 OXY 2019 FORM 10-K

MANAGEMENT’S DISCUSSION AND ANALYSIS

STRATEGY

GENERAL

Occidental is focused on delivering a unique shareholder value proposition through continual enhancements to its asset quality, organizational capability and innovative technical applications that provide competitive advantages. Occidental’s integrated business provides conventional and unconventional opportunities through which to grow value. Occidental aims to maximize shareholder returns through a combination of:

Ø Maintaining a sustainable and sector-leading dividend;

Ø Allocating capital to high-return, short-cycle and long-cycle, cash-flow generating opportunities across its integrated business;

Ø Generating free cash flow growth to reduce debt and return cash to shareholders;

Ø Achieving production growth rates of up to 5% over the long-term; and

Ø Maintaining a strong balance sheet to secure business and enhance shareholder value.

Occidental conducts its operations with a focus on sustainability, health, safety and environmental and social responsibility. Capital is employed to operate all assets in a safe and environmentally sound manner. Price volatility is inherent in the oil and gas business, and Occidental’s strategy is to position the business to thrive in an up- or down-cycle commodity price environment.

On August 8, 2019, Occidental closed on its acquisition of Anadarko. The Acquisition added to Occidental’s oil and gas portfolio, primarily in the Permian Basin, DJ Basin and Gulf of Mexico, as well as a significant economic interest in WES. Post-Acquisition, Occidental’s diversified portfolio provides numerous competitive advantages. Occidental is now the largest oil and gas leaseholder in the United States on a net acreage basis with ample opportunities in the Permian Basin, DJ Basin, Powder River Basin and the Gulf of Mexico with the ability to selectively deploy capital in a way that optimizes capital intensity. As the acquired assets are integrated and developed, Occidental will utilize its subsurface and operating expertise to improve productivity and reduce full cycle costs.

KEY PERFORMANCE INDICATORS

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

Ø Health, safety and environmental and sustainability-related performance measures;

Ø Achieving debt reduction targets;

Ø Total shareholder return, including dividends;

Ø Maintaining investment grade credit metrics;

Ø Return on capital employed (ROCE) and cash return on capital employed (CROCE);

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

Ø Acquisition-related synergy and divestiture targets.

OIL AND GAS SEGMENT

BUSINESS STRATEGY

Occidental’s oil and gas segment focuses on long-term value creation and leadership in sustainability, health, safety and the environment. In each core operating area, Occidental’s operations benefit from scale, technical expertise, decades of high-margin inventory, environmental and safety leadership, and commercial and governmental collaboration. These attributes allow Occidental to bring additional production quickly to market, extend the life of older fields at lower costs, and provide low-cost returns-driven growth opportunities with advanced technology.

With the completion of the Acquisition, Occidental became the largest U.S. producer of oil and liquids in the second half of 2019, allowing Occidental to maximize cash margins on a BOE basis. Through the Acquisition, Occidental acquired modern 3D seismic data pertaining to approximately 450,000 square miles of core domestic development areas. This resulted in a 40% increase in Occidental’s Permian seismic inventory. The advantages that Occidental’s diversified portfolio provides, coupled with unmatched subsurface characterization ability and the proven ability to execute, ensures that Occidental is positioned for full-cycle success in the years ahead. The oil and gas segment continues to focus on integration of the newly acquired assets and efforts to realize synergies at an early stage to deliver lower breakeven costs and generate excess free cash flow.

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As a result of Occidental’s strategic positioning, Occidental’s assets provide current production and a future portfolio of projects that are flexible and have short-cycle investment paybacks. Together with Occidental’s technical capabilities, the oil and gas segment strives to achieve low development and operating costs to maximize full-cycle value of the assets.

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

Ø    Operating and developing areas where reserves are known to exist and optimizing capital intensity in core areas, primarily in the Permian Basin, DJ Basin, Gulf of Mexico, UAE, Oman, Qatar and Colombia;

Ø    Maintaining a disciplined and prudent approach to capital expenditures with a focus on high-return, short-cycle, cash-flow-generating opportunities and an emphasis on creating value and further enhancing Occidental’s existing positions;

Ø    Focusing Occidental’s subsurface characterization and technical activities on unconventional opportunities, primarily in the Permian Basin;

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

Ø    Focusing on cost-reduction efficiencies and innovative technologies to reduce carbon emissions.

In 2019, oil and gas capital expenditures were approximately $5.5 billion and primarily focused on Occidental’s assets in the Permian Basin, the DJ Basin, Gulf of Mexico and Oman.

BUSINESS ENVIRONMENT

Oil and gas prices are the major variables that drive the industry’s financial performance. The following table presents the average daily West Texas Intermediate (WTI), Brent and New York Mercantile Exchange (NYMEX) prices for 2019 and 2018:

	2019		2018		% Change
WTI oil ($/barrel)	$	57.03	$	64.77	(12	)%
Brent oil ($/barrel)	$	64.18	$	71.53	(10	)%
NYMEX gas ($/Mcf)	$	2.67	$	2.97	(10	)%

The following table presents Occidental’s average realized prices for continuing operations as a percentage of WTI, Brent and NYMEX for 2019 and 2018:

	2019		2018
Worldwide oil as a percentage of average WTI	98	%	94	%
Worldwide oil as a percentage of average Brent	87	%	85	%
Worldwide NGL as a percentage of average WTI	30	%	41	%
Worldwide NGL as a percentage of average Brent	27	%	37	%
Domestic natural gas as a percentage of NYMEX	49	%	54	%

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

DOMESTIC INTERESTS

BUSINESS REVIEW

Occidental conducts its domestic operations through land leases, subsurface mineral rights it owns, or a combination of both. 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. Occidental has leasehold and mineral interests in 14.4 million net acres, of which approximately 39% is leased, 55% is owned subsurface mineral rights and 6% is owned land with mineral rights. Included in Occidental’s total net acres is approximately 7 million net acres of primarily undeveloped minerals that pass through Colorado, Wyoming and into Utah. Occidental holds fee ownership of oil and gas, mineral and hardrock mineral rights in this area.

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

Note: Operations sold include South Texas (sold in April 2017), Piceance (sold in March 2016) and Williston (sold in November 2015).

DOMESTIC ASSETS

1. Powder River Basin 2. DJ Basin 3. Greater Natural Buttes 4. Permian Basin 5. Gulf of Mexico

Permian Basin

The Permian 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 more than 30% of total United States oil production in 2019.

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. Occidental has a leading position in the Permian Basin, producing approximately 11% of total oil in

the basin. Occidental’s position in the Texas Delaware sub-basin was further enhanced through assets acquired as part of the Acquisition. By exploiting the natural synergies between Permian Resources and Permian EOR, Occidental is able to deliver unique short- and long-term advantages, efficiencies and expertise across its Permian Basin operations. Occidental expects to decrease its Permian Basin full-cycle breakeven costs, while continuing to expand its high-quality, low-cost

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breakeven inventory. Occidental expects the combined technical advancements, infrastructure utilization opportunities and operations across over 3.1 million net acres will provide sustainability of Occidental’s low-cost position in the Permian Basin.

In the next few years, growth within Occidental’s Permian Basin portfolio is expected to be focused in the Permian Resources unconventional assets. In 2019, Occidental spent approximately $3.8 billion of capital in the Permian Basin, of which over 85% was spent on Permian Resources assets. In 2020, Occidental expects to allocate approximately 40% of its worldwide capital budget to Permian Resources for development and approximately 8% to Permian EOR for the expansion of existing facilities to increase CO₂ production and injection capacity.

In November 2019, Occidental and Ecopetrol formed a joint venture to explore and develop approximately 97,000 net acres of Occidental’s Midland sub-basin properties in the Permian Basin. Occidental owns a 51% interest in the joint venture and is the operator. In exchange for its 49% interest, Ecopetrol paid $750 million in cash to Occidental at closing and will carry 75% of Occidental’s share of capital expenditures, up to $750 million. The joint venture allows Occidental to accelerate its development plans in the Midland Basin, where it currently has minimal activity. Occidental will retain production and cash flow from its existing operations in the Midland Basin.

1. Delaware Basin 2. Central Basin Platform 3. Midland Basin

Permian Resources

Permian Resources unconventional oil development projects provide very short-cycle investment payback, averaging less than two years, and generate some of the highest margin and returns of any oil and gas projects in the world. These investments contribute cash flow and production growth, while increasing long-term value and sustainability through higher return on capital employed.

As part of the Acquisition, Occidental acquired Anadarko’s oil and gas operations in Permian Resources which included approximately 370,000 net acres, including 240,000 net acres located primarily within Loving and Reeves Counties. A new well design and flowback method will be implemented in 2020, which is expected to lower the overall well cost while improving completion efficiency. The 2020 plan contemplates the continued development of the newly acquired acreage. Occidental’s share of production from the acquired assets in Permian Resources was approximately 159 thousand BOE per day (MBOE/d) from the Acquisition date through December 31, 2019. Overall in 2019, Permian Resources produced approximately 355 MBOE/d from approximately 7,600 gross wells. In 2019, Permian Resources added 173 MMBOE to Occidental’s proved reserves for improved recovery additions.

Permian EOR

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 high-value enhanced oil production. With 34 active CO₂ floods and over 40 years of experience, Occidental is the industry leader in Permian Basin CO₂ flooding, which can increase ultimate oil recovery by 10% to 25%. Technology improvements, such as the recent trend toward vertical expansion of the CO₂ flooded interval into residual oil zone targets, continue to yield more recovery from existing projects. Occidental utilizes workover rigs to drill extra depth into additional CO₂ floodable sections of the reservoir. Occidental completed 72 well workovers in 2019 and has plans to complete 81 well workovers in 2020. In 2019, Permian EOR added 14 MMBOE to Occidental’s proved

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reserves for improved recovery additions, primarily as a result of executing CO₂ flood development projects and expansions. Occidental’s share of production from Permian EOR was approximately 154 MBOE/d in 2019.

Significant opportunities also remain to gain additional recovery by expanding Occidental’s existing CO₂ projects into new portions of reservoirs that have only been water-flooded. 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 addition, OLCV continues making progress towards supplying anthropogenic, or man-made, CO₂ for the purpose of carbon capture, utilization and storage in Occidental’s Permian EOR operations.

DJ Basin

Through the Acquisition, Occidental is Colorado’s top oil and gas producer with interest in approximately 650,000 net acres. Production is derived from 2,700 operated vertical wells and 2,000 operated horizontal wells primarily focused in 460,000 net acres in the Niobrara and Codell formations. The DJ Basin provides competitive economics, low breakeven costs and free cash-flow generation.

Occidental’s share of production from the DJ Basin was approximately 303 MBOE/d from the Acquisition date through December 31, 2019. Horizontal drilling results in the field continue to be strong, with improved operational efficiencies in drilling and completions.

License to operate continues to be a key focus moving into 2020. Occidental has a majority of its planned 2020 completions activity permitted. Occidental maintains optionality by flexing resources between DJ Basin and another emerging high rate- of-return program in the Powder River Basin.

Powder River

In the southern Powder River Basin, Occidental acquired through the Acquisition approximately 400,000 net acres mainly located in Converse County, Wyoming. The field contains the Turner, Niobrara, Mowry and Parkman formations that hold both liquids and natural gas.

Greater Natural Buttes

The Greater Natural Buttes area in eastern Utah is a tight-gas asset producing primarily from the Mesa Verde, Wasatch and Blackhawk formations. Occidental uses cryogenic and refrigeration processing facilities in this area to extract NGLs from the natural-gas stream. There was no development activity in this field during 2019 due to capital being allocated to higher-margin projects.

OFFSHORE DOMESTIC ASSETS

Gulf of Mexico

Occidental owns a working interest in 230 blocks in the Gulf of Mexico, operates 10 active floating platforms and holds interests in 18 active fields. In 2020, Occidental will take advantage of its extensive infrastructure across the Gulf of Mexico to execute its long-term plan for development and exploration. It will operate one floating drillship and three platform rigs together with a floating well service rig to cost effectively develop known resources and perform exploration activities to identify tie-back opportunities near existing facilities. The following table shows areas of continuing development in the Gulf of Mexico along with the corresponding working interest in those areas. Acquired assets in the Gulf of Mexico produced approximately 147 MBOE/d from the Acquisition date through December 31, 2019. In addition to its portfolio of undeveloped leases, Occidental’s Gulf of Mexico exploration assets are primarily related to a deepwater discovery located with tie-back proximity to the Horn Mountain platform.

Development Area	Working Interest
Horn Mountain	100	%
Marlin	100	%
Holstein	100	%
Caesar Tonga	34	%
Constellation	33	%
Lucius	49	%
K2 Complex	42	%

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INTERNATIONAL INTERESTS

BUSINESS REVIEW

Occidental conducts its ongoing international operations in two sub-regions: the Middle East and Latin America. Its activities include oil, natural gas and NGL production through direct working-interest and production sharing contracts (PSC).

Production Sharing Contracts

Occidental’s interest in Oman and Dolphin are subject to PSCs. Under such contracts, Occidental records a share of production and reserves to recover certain development and production costs and an additional share for profit. In addition, certain contracts in Colombia are subject to contractual arrangements similar to a PSC. These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts. Occidental’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, Occidental’s net economic benefit from these contracts is greater when product prices are higher.

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

Note: Operations sold, exited or held for sale include the Africa Assets (sold in 2019 or held for sale at December 31, 2019), Qatar (exited in 2019) and other Middle East and North Africa operations exited in 2016 and 2015.

MIDDLE EAST ASSETS

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Oman

In Oman, Occidental is the operator of Block 9 with a 50% working interest, Block 27 with a 65% working interest, Block 53 with a 45% working interest and Block 62 with a 100% working interest. In 2018 and 2019, Occidental entered into Exploration and Production Sharing Agreements for Blocks 30, 51, 65 and 72, which increased the acreage that Occidental holds in Oman from 2.3 million to 6.0 million gross acres and the potential well inventory locations to approximately 10,000. In 2019, Occidental’s share of production was 89 MBOE/d.

The Block 9 contract expires in 2030 and the Block 27 contract expires in 2035. Occidental’s share of production for Blocks 9 and 27 was 27 MBOE/d and 7 MBOE/d in 2019, respectively. The Block 53 (Mukhaizna Field) contract expires in 2035 and is a major world-class pattern steam flood project for enhanced oil recovery that utilizes some of the largest mechanical vapor compressors ever built. Since assuming operations in Mukhaizna in 2005, Occidental has drilled over 3,450 new wells and has increased gross production by over 15 fold. Occidental’s share of production for Block 53 was 33 MBOE/d in 2019. Subject to declaration of commerciality, Block 62 will expire in 2028. Occidental’s share of production for Block 62 was 22 MBOE/d in 2019.

United Arab Emirates

In 2011, Occidental acquired a 40% participating interest in Al Hosn Gas, joining with the Abu Dhabi National Oil Company (ADNOC) in a 30-year joint venture agreement. In 2019, Occidental’s share of production from Al Hosn Gas was 251 MMcf per day of natural gas and 40,000 barrels per day of NGL and condensate. Al Hosn Gas includes gas processing facilities which are discussed further in “Marketing and Midstream Segment - Gas Processing, Gathering and CO₂ .”

In 2019, Occidental acquired a 9-year exploration concession and, subject to a declaration of commerciality, a 35-year production concession for onshore Block 3 which covers an area of approximately 1.5 million acres and is adjacent to Al Hosn Gas. 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 oil and gas operations.

Qatar

In Qatar, Occidental partners in the Dolphin Energy project, an investment that is comprised of two separate economic interests. Occidental has a 24.5% interest in the upstream operations to develop and produce natural gas, NGL and condensate from Qatar’s North Field through mid-2032. Occidental also has a 24.5% interest in Dolphin Energy Limited, which operates a pipeline and is discussed further in “Marketing and Midstream Segment – Pipeline.” Occidental’s net share of production from the Dolphin upstream operations was 42 MBOE/d in 2019.

In 2019, Occidental’s contract for Idd El Shargi North Dome (ISND) expired, and there was a mutually agreed early termination of its Idd El Shargi South Dome (ISSD) contract.

LATIN AMERICA ASSETS

1. La Cira-Infantas Waterflood Area 2. Llanos Norte Basin 3. Teca Heavy Oil Area 4. Putumayo Basin

Colombia

Occidental has working interests in the La Cira-Infantas and Teca areas and has operations within the Llanos Norte Basin. Occidental’s interests range from 39% to 61% and certain interests expire between 2023 and 2038, while others extend through the economic limit of the areas.

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In 2019, Occidental and Ecopetrol initiated Teca steam flood project second phase development activities. During 2019, 17 new wells were drilled, and the initial facility upgrade project began.

Occidental also farmed into two additional blocks in the prospective Putumayo Basin, consolidating a position of 1.6 million gross acres in the basin.

Occidental’s net share of production from Colombia was 33 MBOE/d in 2019.

AFRICA ASSETS

In September 2019, Occidental completed the sale of Mozambique LNG assets to Total for approximately $4.2 billion. In January 2020, Occidental completed the sale of South Africa assets to Total. Occidental and Total continue to work toward completing the sales of the remaining Africa Assets during 2020. The results of the Africa Assets are presented as discontinued operations in the Consolidated Statements of Operations and Cash Flows. The remaining Africa Assets are classified as held-for-sale and not considered part of Occidental’s ongoing international operations as of December 31, 2019. Operations in Algeria involve production and development activities in Blocks 404A and 208 of Algeria’s Sahara Desert. The El Merk Central Processing Facility (CPF) in Block 208 processed produced oil and NGL, while the Hassi Berkine South and Ourhoud CPFs in Block 404A processed only produced oil. Ghana operations include production and development activities located offshore in the West Cape Three Point Block and the Deepwater Tano Block.

PROVED RESERVES

Proved oil, NGL 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, NGL 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.

The following table shows the 2019, 2018 and 2017 calculated average prices for both WTI and Brent oil prices, as well as the NYMEX gas prices:

	2019		2018		2017
WTI oil ($/barrel)	$	55.69	$	65.56	$	51.34
Brent oil ($/barrel)	$	63.03	$	72.20	$	54.93
NYMEX gas ($/Mcf)	$	2.58	$	3.10	$	2.98

Occidental had proved reserves from continuing operations at year-end 2019 of 3,827 million barrels of oil equivalent (MMBOE) (excluding the Africa Assets), compared to the year-end 2018 amount of 2,752 MMBOE. Proved developed reserves represented approximately 76% and 73% of Occidental’s total proved reserves at year-end 2019 and 2018, respectively. The following table shows the breakout of Occidental’s proved reserves from continuing operations by commodity as a percentage of total proved reserves:

	2019		2018
Oil	52	%	57	%
Natural gas	29	%	25	%
NGL	19	%	18	%

Occidental does not have any reserves from non-traditional sources. For further information regarding Occidental’s proved reserves, see “Supplemental Oil and Gas Information.”

The following table details the proved developed and undeveloped reserves related to the Africa Assets that were presented as held for sale at December 31, 2019:

	Oil (MMbbl)	NGL(MMbbl)	Natural Gas (Bcf)	Total (MMBOE)
Proved developed reserves	99	7	19	109
Proved undeveloped reserves	14	—	11	16

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CHANGES IN PROVED RESERVES

Occidental’s total proved reserves from continuing operations increased 1,075 MMBOE in 2019, which was primarily driven by additions of 1,311 MMBOE primarily from the Acquisition and 356 MMBOE from Occidental’s development program. Changes in reserves were as follows:

MMBOE	2019
Revisions of previous estimates	(200	)
Improved recovery	293
Extensions and discoveries	63
Purchases	1,311
Sales	(29	)
Production	(363	)
Total	1,075

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 may negatively or positively affect Occidental’s reserves.

Purchases of Proved Reserves

In 2019, Occidental purchased proved reserves of 1,311 MMBOE primarily as part of the Acquisition, including proved reserves in the Permian Delaware Basin, the DJ Basin and Gulf of Mexico. As part of smaller asset purchases separate from the Acquisition, Occidental purchased proved reserves in Permian Resources New Mexico.

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 reserves under PSCs because more oil is required to recover costs. Conversely, when prices rise, Occidental’s share of proved reserves decreases for PSCs and economically recoverable reserves may increase for other operations. 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.

In 2019, Occidental had negative revisions of 200 MMBOE, primarily related to negative price revisions, changes to development plans and reservoir performance in the Permian Basin.

Improved Recovery

In 2019, Occidental added proved reserves of 293 MMBOE mainly associated with the Permian Basin. These properties comprise both conventional projects, which are characterized by the deployment of EOR development methods, largely employing application of CO₂ flood, waterflood or steam flood, and unconventional projects. These types of conventional EOR development methods can be applied through existing wells, though additional drilling is frequently required to fully optimize the development configuration. Waterflooding is the technique of injecting water into the formation to displace the oil to the offsetting oil production wells. The use of either CO₂ or steam flooding depends on the geology of the formation, the evaluation of engineering data, availability and cost of either CO₂ or steam and other economic factors. Both techniques work similarly to lower viscosity causing the oil to move more easily to the producing wells. Many of Occidental’s projects, including unconventional projects, rely on improving permeability to increase flow in the wells. In addition, some improved recovery comes from drilling infill wells that allow recovery of reserves that would not be recoverable from existing wells.

Extensions and Discoveries

Occidental also added proved reserves from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2019, extensions and discoveries added 63 MMBOE primarily related to the recognition of proved undeveloped reserves due to post-Acquisition activities for acquired properties in the Permian Basin and Gulf of Mexico.

Sales of Proved Reserves

In 2019, Occidental sold 29 MMBOE in proved reserves mainly related to non-core Permian Basin acreage.

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Proved Undeveloped Reserves

Occidental had proved undeveloped reserves at year-end 2019 of 904 MMBOE, compared to the year-end 2018 amount of 750 MMBOE. Changes in proved undeveloped reserves were as follows:

MMBOE	2019
Revisions of previous estimates	(166	)
Improved recovery	192
Extensions and discoveries	36
Purchases	317
Sales	(29	)
Transfer to proved developed reserves	(196	)
Total	154

Occidental incurred approximately $1.8 billion in 2019 to convert proved undeveloped reserves to proved developed reserves. Permian Basin added approximately 500 MMBOE through improved recovery and purchases.

The 2019 additions to proved undeveloped reserves were partially offset by 196 MMBOE transfers to proved developed reserves, primarily in the Permian Basin, 166 MMBOE of negative revisions of previous estimates primarily related to negative price revisions, changes to development plans and reservoir performance in the Permian Basin.

Occidental’s highest-return projects and most active development areas are located in the Permian Basin, which represented 44% of the proved undeveloped reserves as of December 31, 2019. Nearly half of Occidental’s 2020 capital program of $5.3 billion is allocated to the development program in the Permian Basin. Overall, Occidental plans to spend approximately $3.6 billion over the next five years to develop its proved undeveloped reserves in the Permian Basin.

Occidental’s proved undeveloped reserves in international locations are associated with approved long-term international development projects.

RESERVES EVALUATION AND REVIEW PROCESS

Occidental’s estimates of proved reserves and associated future net cash flows as of December 31, 2019, 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 reliable 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. Proved undeveloped reserves are supported by a five-year, detailed, field-level development plan, which includes the timing, location and capital commitment of the wells to be drilled. The development plan is reviewed and approved annually by senior management and technical personnel. Annually a detailed review is performed by Occidental’s Worldwide Reserves Group and its technical personnel on a lease-by-lease basis to assess whether proved undeveloped reserves are being converted on a timely basis within five years from the initial disclosure date. Any leases not showing timely transfers from proved undeveloped reserves to proved developed reserves are reviewed by senior management to determine if the remaining reserves will be developed in a timely manner and have sufficient capital committed in the development plan. Only proved undeveloped reserves that are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the proved undeveloped reserves associated with international operations are expected to be developed beyond the five years and are tied to approved long-term development plans.

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. SEC rules and regulations, including the internal audit and review of Occidental’s oil and gas reserves data. He has over 35 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

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of Petroleum Evaluation Engineers, the Colorado School of Mines Potential Gas Committee and the UNECE Expert Group on Resource Management. He 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 addition, Occidental utilized Miller and Lents, Ltd. (M&L), independent petroleum engineering consultants who were previously retained by Anadarko, to review the annual oil and gas reserve estimation processes associated with the Anadarko reserves. For additional reserves information, see Supplemental Oil and Gas Information under Item 8 of this Form 10-K.

In 2019, both Ryder Scott and M&L 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, 2019, in accordance with SEC regulatory standards. Ryder Scott and M&L reviewed the specific application of such methods and procedures for selected oil and gas properties considered to be a valid representation of Occidental’s 2019 year-end total proved reserves portfolio. In 2019, Ryder Scott reviewed approximately 20% of legacy 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 80% of legacy Occidental’s existing proved oil and gas reserves. M&L reviewed approximately 90% of the Anadarko proved oil and gas reserves.

Management retained Ryder Scott and M&L 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. Neither Ryder Scott nor M&L has been engaged to render an opinion as to the reasonableness of reserves quantities reported by Occidental. Occidental has filed Ryder Scott’s and M&L’s independent reports as exhibits to this Form 10-K.

Based on its reviews, including the data, technical processes and interpretations presented by Occidental, Ryder Scott and M&L have concluded that the overall procedures and methodologies Occidental utilized in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties are appropriate for the purpose thereof and comply with current SEC regulations.

INDUSTRY OUTLOOK

The petroleum industry is highly competitive and subject to significant volatility due to various market conditions. WTI and Brent oil price indexes increased throughout 2019 closing at $61.06 per barrel and $66.00 per barrel, respectively, as of December 31, 2019.

Oil prices will continue to be affected by: (i) global supply and demand, which are generally a function of global economic conditions, inventory levels, production disruptions, technological advances, regional market conditions and the actions of OPEC, other significant producers and governments; (ii) transportation capacity, infrastructure constraints, and costs in producing areas; (iii) currency exchange rates; and (iv) the effect of changes in these variables on market perceptions.

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

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 difficult to predict the future direction of oil, NGL and domestic gas prices reliably. For purposes of the current capital plan, Occidental will continue to focus on allocating capital to its highest-return assets with the flexibility to adjust based on fluctuations in commodity prices. International gas prices are generally fixed under long-term contracts. Occidental continues to adjust capital expenditures in line with current economic conditions with the goal of keeping returns well above its cost of capital.

OXY 2019 FORM 10-K 29

MANAGEMENT’S DISCUSSION AND ANALYSIS

CHEMICAL SEGMENT

BUSINESS STRATEGY

OxyChem seeks to generate cash flow in excess of its normal capital expenditure requirements and achieve above-cost-of-capital returns. The chemical segment focuses on being a low-cost producer in order to maximize cash flow generation. OxyChem concentrates on the chlorovinyls chain, beginning with the co-production of caustic soda and chlorine. Caustic soda and chlorine are marketed to external customers. In addition, chlorine, together with ethylene, is converted through a series of intermediate products into 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 2019, capital expenditures for OxyChem totaled $267 million.

BUSINESS ENVIRONMENT

In 2019, the United States economic growth rate, estimated to be 2.3%, was lower than the 2.9% experienced in 2018, which resulted in lower demand for caustic soda and PVC. Ethylene prices trended downward in the first half of 2019 before increasing in the second half of the year with the total year average ethylene price being less than that of 2018. Pricing for caustic soda and PVC was lower in 2019, partially offset by lower energy and feedstock costs. Domestic demand for caustic soda and PVC was negatively impacted by slower or no growth in manufacturing, automotive and construction markets as well as a weaker pulp and paper market.

BUSINESS REVIEW

BASIC CHEMICALS

The lower U.S. growth rate resulted in lower domestic demand as the industry chlor-alkali operating rates decreased by 3% compared to 2018. Liquid caustic soda prices were lower both domestically and globally in 2019 due to weaker demand in the alumina and pulp and paper market segments, which was partially offset by lower energy prices than in 2018. Exports of downstream chlorine derivatives into the vinyls chain decreased in 2019 as demand for PVC lagged year-over-year.

VINYLS

Demand for PVC in 2019 decreased year-over-year in total as domestic demand was down 3% from 2018 while export demand increased by less than 1%. Domestic demand was weaker in the first half of 2019 due to lower construction demand caused by weather conditions and demand did not fully recover in the second half of 2019. Export demand growth was driven by emerging economy growth and competitive North American feedstock costs. Export volume remains a significant portion of PVC sales representing over 34% of total North American producer’s production. PVC industry operating rates decreased by 1% compared to 2018. Industry PVC margins decreased in 2019 due to lower PVC prices partially offset by lower ethylene prices in the first half of 2019 and lower energy prices than in 2018.

INDUSTRY OUTLOOK

Industry performance will depend on the health of the global economy, specifically in the housing, construction, automotive and durable goods markets. The housing and construction markets are expected to strengthen over the next year while the automotive and durable goods markets look to remain flat or decrease slightly. Margins also depend on market supply and demand balances and feedstock and energy prices. Weakening in the petroleum industry may negatively affect the demand and pricing of a number of Occidental’s products that are consumed by industry participants. U.S. commodity export markets will continue to be impacted by the relative strength of the U.S. dollar.

BASIC CHEMICALS

Continued improvement in the United States housing market, offset by flat to weakening automotive and durable goods markets, are expected to result in a flattening to a moderate increase in demand for basic chemical products in 2020. Export demand for caustic soda is expected to be similar to 2019 levels driven by limited demand improvement into the alumina market. Chlor-alkali operating rates should improve moderately with higher demand and continued competitive energy and raw material pricing as compared to global feedstock costs. Businesses such as calcium chloride and muriatic acid may be affected by flatter U.S. oil growth trends, as well as shifts in drilling technology.

VINYLS

North American demand for PVC is expected to improve in 2020 over 2019 levels, as growth in residential construction spending is expected to rebound along with upside potential driven by new infrastructure projects. Although overall demand is expected to increase in North America, operating rates are anticipated to remain relatively flat in 2020 as new PVC capacity is expected to enter the market. Growth in the export market is likely along with favorable ethylene costs continuing in 2020.

30 OXY 2019 FORM 10-K

MANAGEMENT’S DISCUSSION AND ANALYSIS

MARKETING AND MIDSTREAM SEGMENT

BUSINESS STRATEGY

The marketing and midstream segment strives to maximize realized value by optimizing the use of its gathering, processing, transportation, storage and terminal commitments and by providing access to domestic and international markets. To generate returns, the segment evaluates opportunities across the value chain and uses its assets to provide services to Occidental’s subsidiaries, as well as third parties. The marketing and midstream segment operates gathering systems, gas plants, co-generation facilities and storage facilities and invests in entities that conduct similar activities. From August 8, 2019, to December 31, 2019, WES’s operating results were consolidated in the marketing and midstream segment. As of December 31, 2019, Occidental will account for its ownership investment in WES under the equity method of accounting. See Note 16 - Investments and Related-Party Transactions in the Notes to Consolidated Financial Statements.

Also within the marketing and midstream segment is OLCV. OLCV seeks to capitalize on Occidental’s EOR leadership by developing carbon capture, utilization and storage projects that source anthropogenic CO₂ and promote innovative technologies that drive cost efficiencies and economically grow Occidental’s business while reducing emissions.

This segment also seeks to minimize the costs of gas, power and other commodities used in Occidental’s various businesses. Capital is employed to sustain or expand assets to improve the competitiveness of Occidental’s businesses. In 2019, capital expenditures related to the marketing and midstream segment totaled $461 million (including $365 million related to WES).

BUSINESS ENVIRONMENT

Marketing and midstream segment earnings are affected by the performance of its various businesses, including its marketing, gathering and transportation, gas processing and power-generation assets. The marketing business aggregates, markets and stores Occidental and third-party volumes. Marketing performance is affected primarily by commodity price changes and margins in oil and gas transportation and storage programs. The marketing business results can experience significant volatility depending on commodity price changes and the Midland to Gulf Coast spreads. In 2019, the Permian takeaway capacity increased as several new third-party pipelines were completed, which in turn reduced the Midland to Gulf Coast spreads. Gas gathering, processing and transportation results are affected by fluctuations in commodity prices and the volumes that are processed and transported through the segment’s plants, as well as the margins obtained on related services from investments in which Occidental has an equity interest. The 2019 declines in NGL prices and sulfur prices negatively impacted the gas processing business.

BUSINESS REVIEW

MARKETING

The marketing group markets substantially all of Occidental’s oil, NGL and natural gas production, as well as trades around its assets, including contracted transportation and storage capacity. Occidental’s third-party marketing activities focus on purchasing oil, NGL 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 2019, compared to the prior year, marketing results were negatively impacted by the decline in the Midland-to-Gulf Coast spreads, as well as non-cash mark-to-market losses.

OXY 2019 FORM 10-K 31

MANAGEMENT’S DISCUSSION AND ANALYSIS

PIPELINE

Occidental’s pipeline business mainly consists of its 24.5% ownership interest in Dolphin Energy. 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 has capacity to transport up to 3.2 Bcf of natural gas per day and currently transports approximately 2.2 Bcf per day, and up to 2.5 Bcf per day in the summer months.

In 2019, compared to the prior year, pipeline income declined due to the 2018 sale of the Centurion Pipeline common carrier oil pipeline and storage system and the Ingleside Crude Terminal.

GAS PROCESSING, GATHERING AND CO₂

Occidental processes its and third-party domestic wet gas to extract NGL 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 NGL.

As of December 31, 2019, Occidental has 54.5% of limited partner unit interest and a 2% non-voting general partner unit interest in WES. In addition, Occidental has a 2% non-voting limited partner interest in Western Midstream Operating, LP, a consolidated subsidiary of WES. Prior to December 31, 2019 Occidental consolidated WES. As of December 31, 2019, Occidental recognizes WES as an equity method investment. See Note 1 - Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements. WES owns gathering systems, plants and pipelines and earns revenue from fee-based and service-based contracts with Occidental and third parties.

Occidental also has a 40% participating interest in Al Hosn Gas which is designed to process 1.3 Bcf per day of natural gas and separate it into salable gas, condensate, NGL and sulfur. In 2019, the facilities produced approximately 11,500 metric tons per day of sulfur, of which approximately 4,600 metric tons was Occidental’s share. Al Hosn Gas facilities generate revenues from gas processing fees and the sale of sulfur.

In 2019, compared to the prior year, gas processing, gathering and CO₂ results increased primarily due to income from WES partially offset by lower NGL prices and sulfur prices which negatively impacted the gas processing business.

POWER GENERATION FACILITIES

Earnings from power and steam generation facilities are derived from sales to affiliates and third parties.

LOW CARBON VENTURES

OLCV was formed to execute on Occidental’s vision to reduce global emissions and provide a more sustainable future through low carbon energy and products. OLCV capitalizes on Occidental’s extensive experience in utilizing CO₂ for EOR by investing in technologies, developing projects and providing services to facilitate and accelerate the implementation of carbon capture, utilization and storage projects and opportunities for zero-carbon power. Moreover, OLCV is fostering new technologies and business models with the potential to position Occidental as a leader in the production of low-carbon oil and products.

INDUSTRY OUTLOOK

Marketing and midstream segment results can experience volatility depending on the Midland to Gulf Coast spreads and commodity price changes. The decline in the Midland to Gulf Coast spreads in the second half of 2019 has continued into the early part of 2020. If the spread remains at current levels or are lower for the rest of 2020, this could significantly reduce margins in the marketing business. To a lesser extent, declines in commodity prices, including NGL and sulfur prices, would reduce the results for the gas processing business.

32 OXY 2019 FORM 10-K

MANAGEMENT’S DISCUSSION AND ANALYSIS

SEGMENT RESULTS OF OPERATIONS AND ITEMS AFFECTING COMPARABILITY

SEGMENT RESULTS OF OPERATIONS

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

The following table sets forth the sales and earnings of each operating segment and corporate items for the years ended December 31:

millions, except per share amounts	2019			2018			2017
NET SALES (a)
Oil and Gas	$	13,423		$	10,441		$	7,870
Chemical	4,102			4,657			4,355
Marketing and Midstream	4,132			3,656			1,157
Eliminations	(1,264		)	(930		)	(874		)
Total	$	20,393		$	17,824		$	12,508
SEGMENT RESULTS AND EARNINGS
Domestic	$	838		$	621		$	(589	)
International	1,683			1,896			1,767
Exploration	(169		)	(75		)	(67		)
Oil and Gas	2,352			2,442			1,111
Chemical	799			1,159			822
Marketing and Midstream	241			2,802			85
Total	$	3,392		$	6,403		$	2,018
Unallocated corporate items
Interest expense, net	(1,002		)	(356		)	(324		)
Income taxes	(693		)	(1,477		)	(17		)
Other	(2,204		)	(439		)	(366		)
Income (loss) from continuing operations	$	(507	)	$	4,131		$	1,311
Discontinued operations, net	(15		)	—			—
Net income (loss)	(522		)	4,131			1,311
Less: Net income attributable to noncontrolling interests	(145		)	—			—
Less: Preferred stock dividends	(318		)	—			—
Net income (loss) attributable to common stockholders	$	(985	)	$	4,131		$	1,311
Net income (loss) attributable to common stockholders—basic	$	(1.22	)	$	5.40		$	1.71
Net income (loss) attributable to common stockholders—diluted	$	(1.22	)	$	5.39		$	1.70

^(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.

OXY 2019 FORM 10-K 33

MANAGEMENT’S DISCUSSION AND ANALYSIS

ITEMS AFFECTING COMPARABILITY

OIL AND GAS SEGMENT

Results of Operations

millions	2019			2018			2017
Segment Sales	$	13,423		$	10,441		$	7,870
Segment Results (a)
Domestic	$	838		$	621		$	(589	)
International	1,683			1,896			1,767
Exploration	(169		)	(75		)	(67		)
Total	$	2,352		$	2,442		$	1,111
Items affecting comparability
Asset sale gains, net (b)	$	475		$	—		$	655
Asset impairments and related items domestic (c)	$	(288	)	$	—		$	(397	)
Asset impairments and related items international (d)	$	(39	)	$	(416	)	$	(4	)
Oil collars mark-to-market gains	$	(107	)	$	—		$	—

^(a)  Results include significant items affecting comparability discussed in the footnotes below.

^(b)  The 2019 amount included gain on sale of a portion of Occidental’s joint venture with Ecopetrol and a loss on sale of real estate assets. The 2017 gain on sale of assets included the sale of South Texas and non-core acreage in the Permian Basin.

^(c)  The 2019 amount included $285 million of impairment and related charges associated with domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities. The 2017 amount included $397 million of impairment and related charges associated with non-core proved and unproved Permian acreage.    

^(d)  The 2019 amount related to Occidental’s mutually agreed early termination of its Qatar ISSD contract. The 2018 amount consisted of impairment and related charges associated with ISND and ISSD.

The following table sets forth the average realized prices for oil, NGL and natural gas from ongoing operations for each of the three years in the period ended December 31, 2019, and includes a year-over-year change calculation:

millions (except percentages)	2019		Year over Year Change		2018		Year over Year Change		2017
Average Realized Prices
Oil Prices ($ per bbl)
United States	$	54.31	(4	)%	$	56.30	18	%	$	47.91
Latin America	$	57.26	(11	)%	$	64.32	33	%	$	48.50
Middle East	$	61.96	(8	)%	$	67.69	34	%	$	50.38
Total worldwide	$	56.09	(8	)%	$	60.64	24	%	$	48.93
NGL Prices ($ per bbl)
United States	$	16.03	(42	)%	$	27.64	17	%	$	23.67
Middle East	$	21.31	(8	)%	$	23.20	29	%	$	18.05
Total worldwide	$	17.06	(35	)%	$	26.25	21	%	$	21.63
Gas Prices ($ per Mcf)
United States	$	1.31	(18	)%	$	1.59	(31	)%	$	2.31
Latin America	$	7.01	9	%	$	6.43	27	%	$	5.08
Total worldwide	$	1.45	(10	)%	$	1.62	(12	)%	$	1.84

Domestic oil and gas results, excluding items affecting comparability, increased in 2019 compared to 2018 primarily due to higher oil, NGL and natural gas sales volumes mostly due to added production from the Acquisition and increased production in the legacy Occidental Permian Resources operations, partially offset by lower realized oil, NGL and natural gas prices. Domestic oil and gas results, excluding significant items affecting comparability, increased in 2018 compared to 2017 primarily due to an increase in average domestic realized oil prices, higher volumes and lower DD&A rates.

34 OXY 2019 FORM 10-K

MANAGEMENT’S DISCUSSION AND ANALYSIS

International oil and gas results, excluding significant items affecting comparability, decreased in 2019 compared to 2018 primarily due to lower volumes from the expiration of the ISND contract and early termination of the ISSD contract as well as a decrease in realized oil prices in Latin America and the Middle East. International oil and gas results, excluding significant items affecting comparability, increased in 2018 compared to 2017 primarily due to an increase in realized oil prices in Latin America and the Middle East, respectively.

Production

The following table sets forth the production volumes of oil, NGL and natural gas per day from ongoing operations for each of the three years in the period ended December 31, 2019 and includes a year-over-year change calculation:

Production per Day from Ongoing Operations (MBOE/d)	2019	Year over Year Change		2018	Year over Year Change		2017
United States
Permian Resources	355	66	%	214	52	%	141
Permian EOR	154	—	%	154	3	%	150
DJ Basin	120	N/A		—	N/A		—
Gulf of Mexico	58	N/A		—	N/A		—
Other Domestic	27	N/A		4	N/A		5
Total	714	92	%	372	26	%	296
Latin America	34	6	%	32	—	%	32
Middle East
Al Hosn Gas	82	12	%	73	3	%	71
Dolphin	42	5	%	40	(5	)%	42
Oman	89	3	%	86	(9	)%	95
Qatar	35	(36	)%	55	(5	)%	58
Total	248	(2	)%	254	(5	)%	266
Total Production from Ongoing Operations	996	51	%	658	11	%	594
Sold domestic operations	—	N/A		—	N/A		8
Discontinued operations - Africa Assets	33	N/A		—	N/A		—
Total Production (MBOE/d) (a)	1,029	56	%	658	9	%	602

^(a)  Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. Please refer to “Supplemental Oil and Gas Information (unaudited)” for additional information on oil and gas production and sales.

Average daily production volumes from ongoing operations increased in 2019 compared to 2018 primarily due to 264 MBOE/d in acquired production from the Acquisition, including 120 MBOE/d in DJ Basin, 58 MBOE/d in the Gulf of Mexico and 63 MBOE/d in the Delaware Basin, as well as an increase of 78 MBOE/d in the legacy Occidental Permian Resources operations as a result of increased drilling and well productivity.

Average daily production volumes from ongoing operations increased in 2018 compared to 2017 primarily due to higher Permian Resources production which increased by 52% from the prior year, due to developmental drilling activity and improved well performance.

Lease operating expense

The following table sets forth the average lease operating expense per BOE from ongoing operations for each of the three years in the period ended December 31, 2019:

	2019	2018	2017
Average lease operating expense per BOE	$9.19	$11.52	$11.20

Average lease operating expense per BOE, decreased in 2019 compared to 2018 primarily due to operational efficiencies related to maintenance and support cost. Combined 2019 Permian Resources lease operating expense per BOE, was $6.80 which represented a decrease of 6% from the prior year.

Average lease operating costs per BOE, excluding taxes other than on income, increased in 2018 compared to 2017 primarily due to increased surface operations and maintenance costs. Permian Resources lease operating costs per BOE for 2018 decreased by 10% from the prior year, and the fourth quarter of 2018 costs were below $7.00 per BOE, due to continued improved operational efficiencies.

OXY 2019 FORM 10-K 35

MANAGEMENT’S DISCUSSION AND ANALYSIS

CHEMICAL SEGMENT

millions	2019		2018		2017
Segment Sales	$	4,102	$	4,657	$	4,355
Segment Results	$	799	$	1,159	$	822

Chemical segment results decreased in 2019 compared to 2018 due to lower realized caustic soda prices and lower domestic demand across many product lines partially offset by favorable feedstock costs. The 2019 earnings also reflected fees received under a pipeline easement agreement that was executed during the first quarter of 2019.

Chemical segment results increased in 2018 compared to 2017 due to significant improvements in realized caustic soda pricing, strong margins and demand across many product lines and lower ethylene costs, slightly offset by decreased caustic soda export volumes. The 2018 earnings also benefited from the full-year equity contributions from the joint venture ethylene cracker in Ingleside, Texas, and additional earning contributions from the Geismar, Louisiana plant expansion to produce 4CPe.

MARKETING AND MIDSTREAM SEGMENT

millions	2019			2018		2017
Segment Sales	$	4,132		$	3,656	$	1,157
Segment Results (a)	$	241		$	2,802	$	85
Items affecting comparability
Asset and equity investment sale gains (b)	$	114		$	907	$	94
Asset impairments and other charges(c)	$	(1,002	)	$	—	$	(120	)
Interest rate swaps MTM, net(d)	$	30		$	—	$	—

^(a)  Results include items affecting comparability listed below, as well as WES segment results from August 8, 2019 to December 31, 2019 of $541 million.

^(b)  The 2019 amount represented a $114 million gain on the sale of an equity investment in Plains All American Pipeline, L.P. and Plains GP Holdings, L.P. (together, Plains). The 2018 amount represented a gain on sale of non-core domestic midstream assets. The 2017 amount represented a non-cash fair value gain related to Plains.

^(c)  The 2019 amount included a $1 billion charge as a result of recording Occidental’s investment in WES at fair value as of December 31, 2019 upon the loss of control. The 2017 amount represented impairments and related charges related to idled midstream facilities.

^(d)  The 2019 amount represented a $30 million mark-to-market gain on an interest rate swap for WES.

Marketing and midstream segment results, excluding items affecting comparability, decreased in 2019 compared to 2018, primarily due to lower marketing margins from the decrease in the Midland-to-Gulf Coast spreads by approximately $4.00 per barrel and lower pipeline income due to the 2018 sales of the Centurion pipeline and the Ingleside Crude Oil Terminal.

Marketing and midstream segment results, excluding items affecting comparability, increased in 2018 compared to 2017 primarily due to higher marketing margins from improved Midland-to-Gulf Coast spreads and higher gas plant income due to higher domestic NGL prices and higher sulfur prices in connection with Al Hosn Gas sulfur sales.

CORPORATE

Significant corporate items during 2019 include the following:

millions	2019			2018		2017
Items Affecting Comparability
Anadarko acquisition-related costs	$	(1,647	)	$	—	$	—
Bridge loan financing fees	$	(122	)	$	—	$	—
Other acquisition-related pension and other termination benefits	$	37		$	—	$	—
Asset impairments and other charges	$	(22	)	$	—	$	—
Gains on warrants and interest rate swaps, net	$	203		$	—	$	—

36 OXY 2019 FORM 10-K

MANAGEMENT’S DISCUSSION AND ANALYSIS

INCOME TAXES

Deferred tax liabilities, net of deferred tax assets of $3.7 billion, were $9.7 billion at December 31, 2019. 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:

millions	2019			2018			2017
SEGMENT RESULTS
Oil and Gas	$	2,352		$	2,442		$	1,111
Chemical	799			1,159			822
Marketing and Midstream	241			2,802			85
Unallocated corporate items	(3,206		)	(795		)	(690		)
Income from continuing operations before taxes	$	186		$	5,608		$	1,328
Income tax expense (benefit)
Federal and state	(34		)	463			(903		)
Foreign	727			1,014			920
Total income tax expense	$	693		$	1,477		$	17
Income (loss) from continuing operations	$	(507	)	$	4,131		$	1,311
Worldwide effective tax rate	373		%	26		%	1		%

In 2019, Occidental’s worldwide effective tax rate was 373%, which was largely a result of Acquisition-related costs and charges associated with the loss of control of WES for which Occidental received no tax benefit. Excluding the impact of items affecting comparability, Occidental’s worldwide effective tax rate for 2019 would be 36%.

The increase in worldwide effective tax rate from 2017 to 2018 was primarily due to the 2017 remeasurement of net deferred tax liabilities to the new federal corporate income tax rate.

CONSOLIDATED RESULTS OF OPERATIONS

REVENUE AND OTHER INCOME ITEMS

millions	2019		2018		2017
Net sales	$	20,393	$	17,824	$	12,508
Interest, dividends and other income	$	217	$	136	$	99
Gain on sale of equity investments and other assets, net	$	622	$	974	$	667

Price and volume changes generally represent the majority of the change in the oil and gas and chemical segments sales. Marketing and midstream sales are mainly impacted by the change in the Midland-to-Gulf Coast spread for the marketing business and, to a lesser extent, the change in NGL and sulfur prices for the gas processing business.

The increase in net sales in 2019 compared to 2018 was primarily due to higher domestic volumes related to the Acquisition, which added approximately $3.5 billion in net sales as well as increased production activity in Occidental’s Permian Resources operations, partially offset by oil, NGL and natural gas prices in the oil and gas segment and lower realized caustic soda prices in the chemical segment.

The increase in net sales in 2018 compared to 2017 was mainly due to higher oil prices and higher domestic oil volumes, as well as higher marketing margins in the marketing and midstream segment due to improved Midland-to-Gulf Coast spreads and higher realized caustic soda prices in the chemical segment. Average worldwide realized oil prices rose approximately 24% from 2017 to 2018.

The 2019 gain on sale included a net gain of $475 million related to Occidental’s Midland Basin joint venture with Ecopetrol and sale of real estate assets and $114 million from the sale of Occidental’s remaining equity investment in Plains.

The 2018 gain on sale included the sale of non-core domestic midstream assets including the Centurion common carrier pipeline and storage system, Southeast New Mexico oil gathering system, and Ingleside Crude Terminal of $907 million.

The 2017 gain on sale included the sale of South Texas and non-core proved and unproved Permian acreage.

OXY 2019 FORM 10-K 37

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXPENSE ITEMS

millions	2019		2018		2017
Oil and gas operating expense	$	3,246	$	2,761	$	2,427
Transportation expense	$	621	$	152	$	175
Chemical and midstream cost of sales	$	2,791	$	2,833	$	2,938
Purchased commodities	$	1,679	$	822	$	54
Selling, general and administrative	$	882	$	585	$	546
Other operating and non-operating expense	$	1,425	$	1,028	$	878
Depreciation, depletion and amortization	$	5,981	$	3,977	$	4,002
Asset impairments and other charges	$	1,361	$	561	$	545
Taxes other than on income	$	707	$	439	$	311
Anadarko acquisition-related costs	$	1,647	$	—	$	—
Exploration expense	$	246	$	110	$	82
Interest and debt expense, net	$	1,066	$	389	$	345

OIL AND GAS OPERATING EXPENSE

Oil and gas operating expense increased in 2019 from the prior year, primarily due to higher oil and gas production costs for surface operations and maintenance due to increased activity mainly related to acquired operations as part of the Acquisition.

Oil and gas operating expense increased in 2018 from the prior year, primarily due to higher oil and gas production costs for surface operations and downhole maintenance due to increased activity in the Permian Basin as well as an increase in purchased CO₂ injectant.

TRANSPORTATION EXPENSE

Transportation expense increased in 2019 from the prior year, primarily due to increased oil sales volumes, mainly driven by added production and the fulfillment of additional capacity commitments related to the Acquisition.

Transportation expense decreased in 2018 from the prior year due to the 2018 sale of the Centurion Pipeline common carrier oil pipeline and storage system and the Ingleside Crude Terminal.

CHEMICAL AND MIDSTREAM COST OF SALES

Chemical and midstream cost of sales decreased slightly in 2019 from the prior year, primarily due to favorable raw material costs in the chemical segment, partially offset by an increase in midstream operation costs due to WES.

Chemical and midstream cost of sales decreased slightly in 2018 from the prior year, primarily due to lower gas plant and maintenance expenses in the midstream segment.

PURCHASED COMMODITIES

Purchased commodities included purchased oil volumes for which Occidental does not act as agent. Several of these oil purchase agreements commenced in mid-year 2018. The increase in 2019 from the prior year is due to a full year of purchases under these contracts, which are used to ensure the full utilization of committed transportation capacity in the marketing business. Similarly, the purchased oil volumes for contracts effective in late 2017 but in effect for the full year of 2018 caused the increase between those years.

SELLING, GENERAL AND ADMINISTRATIVE

Selling, general and administrative expense increased in 2019 from the prior year, primarily due to higher employee costs related to the Acquisition.

Selling, general and administrative expense increased in 2018 from the prior year due to higher compensation costs.

OTHER OPERATING AND NON-OPERATING EXPENSE

Other operating and non-operating expense increased in 2019 from the prior year, primarily due to higher overhead oil and gas engineering costs related to the Acquisition.

Other operating and non-operating expense increased in 2018 from the prior year, primarily due to higher environmental costs.

TAXES OTHER THAN ON INCOME

Taxes other than on income in 2019 increased from the prior year, primarily due to production taxes on higher oil, NGL and natural gas volumes as well as additional ad valorem tax related to the Acquisition.

Taxes other than on income increased in 2018 from the prior year, primarily due to higher production taxes, which are directly tied to higher commodity prices.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

DEPRECIATION, DEPLETION AND AMORTIZATION

DD&A expense increased in 2019 from prior year, primarily due to increased production related to the Acquisition.

DD&A expense decreased slightly in 2018 from the prior year due to lower domestic DD&A rates due to higher reserves partially offset by higher production volumes and higher DD&A rates in the Middle East.

ASSET IMPAIRMENTS AND OTHER CHARGES

Asset impairments and other charges are primarily related to a $1 billion loss on the December 31, 2019 loss of control of WES. In addition, Occidental incurred impairment charges of approximately $285 million related to domestic undeveloped mineral leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and $39 million related to early termination of its Qatar ISSD contract.

In 2018, Occidental incurred impairment and other charges of approximately $416 million on proved oil and gas properties and inventory in Qatar due to the decline in oil prices. Also in 2018, the marketing and midstream segment incurred approximately $100 million of charges primarily for lower of cost or market adjustments on its crude inventory and line fill.

In 2017, Occidental incurred impairment and other charges of $545 million, of which $397 million related to proved and unproved non-core Permian acreage and $120 million for idled marketing and midstream assets.

ANADARKO ACQUISITION-RELATED COSTS

In 2019, Occidental had the following charges related to the Acquisition: employee severance and related cost of $1 billion; licensing fees for critical seismic data of $401 million; and $213 million for bank, legal and consulting fees. Estimated acquisition-related charges of approximately $1.3 billion that were mostly accrued in 2019 are expected to be mostly paid in 2020.

INTEREST AND DEBT EXPENSE, NET

Interest and debt expense, net, increased in 2019 from the prior year due to an increase in debt issued to partially fund the Acquisition, as well as the debt assumed through the Acquisition.

Interest and debt expense, net, remained relatively consistent between 2018 and 2017 experiencing a small increase in interest paid on debt due to the addition of $1 billion in senior notes.

OTHER ITEMS

Income/(expense) millions	2019			2018			2017
Income tax expense	$	(693	)	$	(1,477	)	$	(17	)
Income from equity investments	$	373		$	331		$	357
Discontinued operations, net	$	(15	)	$	—		$	—

INCOME TAX EXPENSE

Income tax expense decreased in 2019 from the prior year, primarily due to lower pre-tax income, partially offset by charges related to the loss of control of WES and acquisition-related costs for which Occidental did not receive a tax benefit.

Income tax expense increased in 2018 from the prior year, primarily due to Tax Reform in 2017 and higher pre-tax income in 2018. Occidental recorded an income tax benefit in 2017 due to the revaluation of deferred taxes as a result of the corporate tax rate reduction enacted as part of Tax Reform, partially offset by higher pre-tax operating income as a result of a recovery in commodity prices.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2019, Occidental had approximately $3.0 billion in cash and cash equivalents. A substantial majority of this cash is held and available for use in the United States. At December 31, 2019, Occidental had $0.5 billion in restricted cash and restricted cash equivalents, which was primarily associated with a benefits trust for former Anadarko employees that was funded as part of the Acquisition. Restricted cash within the benefits trust will be made available to Occidental as benefits are paid to former Anadarko employees.

DEBT ACTIVITY

In August 2019, Occidental issued $13.0 billion of new senior unsecured notes, consisting of both floating and fixed rate debt. Occidental also borrowed under the Term Loans, which consisted of: (1) a 364-day senior unsecured variable-rate term loan tranche of $4.4 billion and (2) a two-year senior unsecured variable-rate term loan tranche of $4.4 billion. In total, the $21.8 billion in debt issued was used to finance part of the cash portion of the purchase price for the Acquisition. Through the Acquisition, Occidental assumed Anadarko debt with an outstanding principal balance of $11.9 billion.

In 2019, Occidental paid approximately $7.0 billion of long-term debt including a majority of the Term Loans using proceeds from assets sales and available cash.

On June 3, 2019, Occidental entered into an amendment to its existing $3.0 billion revolving credit facility (Occidental RCF) pursuant to which, among other things, the commitments under the Occidental RCF were increased to $5.0 billion at the closing of the Acquisition. Borrowings under the Occidental RCF bear interest at various benchmark rates, including London Inter-Bank Offered Rate (LIBOR), plus a margin based on Occidental’s senior debt-ratings. The facility has similar terms to other debt agreements and does 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 repayment. The facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. Occidental has not drawn down any amounts under the Occidental RCF.

As of December 31, 2019, 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.

With a continued focus on capital and operational efficiencies, Occidental expects to fund its liquidity needs, including future dividend payments, through cash on hand, cash generated from operations, monetization of non-core assets or investments and, if necessary, proceeds from other forms of capital issuance.

CASH FLOW ANALYSIS

CASH PROVIDED BY OPERATING ACTIVITIES

millions	2019		2018		2017
Operating cash flow from continuing operations	$	7,203	$	7,669	$	4,861
Operating cash flow from discontinued operations, net of taxes	172		—		—
Net cash provided by operating activities	$	7,375	$	7,669	$	4,861

Cash provided by operating activities decreased $294 million in 2019 compared to 2018, reflecting Acquisition related costs, higher interest expense, and slightly lower oil prices, which were partially offset by a 92% increase in domestic production volumes.

Cash provided by operating activities increased $2.8 billion in 2018 compared to 2017, reflecting higher realized worldwide oil and NGL prices, which increased by 24% and 21%, respectively, as well as a 25% increase in domestic oil volumes. Operating cash flows in 2018 also benefited from higher marketing margins in the marketing and midstream segment due to improved Midland-to-Gulf Coast spreads and higher chemical margins from significant improvements in caustic soda prices.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

CASH USED BY INVESTING ACTIVITIES

millions	2019			2018			2017
Capital expenditures
Oil and Gas	$	(5,500	)	$	(4,413	)	$	(2,945	)
Chemical	(267		)	(271		)	(308		)
Marketing and Midstream(a)	(461		)	(216		)	(284		)
Corporate	(127		)	(75		)	(62		)
Total	$	(6,355	)	$	(4,975	)	$	(3,599	)
Purchase of businesses and assets, net	(28,088		)	(928		)	(1,064		)
Proceeds from sale of assets and equity investments, net	6,143			2,824			1,403
Other investing activities, net	(573		)	(127		)	181
Investing cash flows from continuing operations	$	(28,873	)	$	(3,206	)	$	(3,079	)
Investing cash flows from discontinued operations	(154		)	—			—
Net cash used by investing activities	$	(29,027	)	$	(3,206	)	$	(3,079	)

^(a) Included $365 million related to WES in 2019.

The increase in cash flows used by investing activities in 2019 compared to 2018 primarily reflected the cash portion of the Acquisition consideration, partially offset by the cash acquired. In 2019, proceeds from the sale of assets and equity investments, net, included the sale of Mozambique LNG assets, the Ecopetrol joint venture, the equity investment in Plains and real estate assets. Occidental’s capital expenditures increased by $1.4 billion in 2019, compared to 2018. The increase was primarily related to the Permian Basin due to its high returns of legacy operations coupled with the addition of assets through the Acquisition in the Permian Basin, DJ Basin and Gulf of Mexico. Occidental’s 2020 capital spending is expected to be $5.3 billion.

The increase in cash flows used by investing activities in 2018 compared to 2017 was a result of additional capital spending, primarily in the Permian Basin due to its high returns. In 2018, proceeds from sale of assets and equity investments, net related to the sale of non-core domestic midstream assets, partially offset by purchases of businesses and assets, net related to the acquisition of a previously leased power and steam cogeneration plant.

CASH PROVIDED (USED) BY FINANCING ACTIVITIES

millions	2019		2018			2017
Net cash provided (used) by financing activities	$	22,193	$	(3,102	)	$	(2,343	)

Cash provided by financing activities in 2019 increased $25.3 billion, compared to 2018, primarily due to net proceeds from long-term debt of $21.6 billion and the issuance of $10.0 billion of preferred shares with a warrant used to fund the Acquisition. These proceeds were partially offset by debt payments of $7.0 billion and dividends on common stock of $2.6 billion.

OXY 2019 FORM 10-K 41

MANAGEMENT’S DISCUSSION AND ANALYSIS

OFF-BALANCE SHEET ARRANGEMENTS

GUARANTEES

Occidental has guaranteed its portion of the debt of Dolphin Energy, an equity method investment, 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. See “Oil and Gas Segment — Business Review — Qatar” and “Segment Results of Operations” for further information about Dolphin. As of December 31, 2019, and 2018, Occidental had provided limited recourse guarantees on approximately $242 million and $244 million, respectively, of Dolphin Energy’s debt, which are limited to certain political and other events.

COMMITMENTS AND OBLIGATIONS

DELIVERY COMMITMENTS

Occidental has made commitments to certain refineries and other buyers to deliver oil, natural gas and NGL. The total amount contracted to be delivered in the United States is approximately 158 million barrels of oil through 2025, 1,346 Bcf of gas through 2035 and 660 million barrels of NGL through 2035. 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.

CONTRACTUAL OBLIGATIONS

The following table summarizes and cross-references Occidental’s contractual obligations, and indicates on- and off-balance sheet obligations as of December 31, 2019:

millions			Payments Due by Year
	Total		2020		2021 and 2022		2023 and 2024		2025 and thereafter
On-Balance Sheet
Long-term debt (Note 7) (a)	$	37,401	$	—	$	11,096	$	5,111	$	21,194
Leases (Note 8) (b)	2,018		608		630		251		529
Asset retirement obligations (Note 1)	4,633		247		271		799		3,316
Other long-term liabilities (c)	3,765		1,054		513		490		1,708
Off-Balance Sheet
Purchase obligations (d)	20,712		3,252		5,704		4,660		7,096
Total	$	68,529	$	5,161	$	18,214	$	11,311	$	33,843

^(a)  Excluded unamortized debt discount and interest on the debt. As of December 31, 2019, interest on long-term debt totaling $18.1 billion is payable in the following years: 2020 - $1.5 billion, 2021 and 2022 - $2.6 billion, 2023 and 2024 - $2.1 billion, 2025 and thereafter - $11.9 billion.

^(b)  Occidental is the lessee under various agreements for real estate, equipment, plants and facilities. See Note 2 - Accounting and Disclosure Changes in the Notes to Consolidated Financial Statements regarding the impact of rules effective January 1, 2019 which require Occidental to recognize most leases, including operating leases, on the balance sheet.

^(c)  Included obligations under postretirement benefit and deferred compensation plans, accrued transportation commitments, severance and change of control obligations related to the Acquisition and other accrued liabilities.

^(d)  Amounts included 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 processing capacity, CO_2, electrical power, steam and certain chemical raw materials. In 2019, Occidental added $7.7 billion of additional long-term commitments as a result of the loss of control of WES. Amounts exclude certain product purchase obligations related to marketing 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 3.89% discount rate.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

LEGAL MATTERS

Occidental 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. Occidental or certain of its subsidiaries also are involved in proceedings under 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 Occidental 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 outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserves for matters, other than for environmental remediation, that satisfy this criteria as of December 31, 2019, and December 31, 2018, were not material to Occidental’s Consolidated Balance Sheets.

On May 30, 2019, a complaint was filed in the Court of Chancery of the State of Delaware by purported Occidental stockholders High River Limited Partnership, Icahn Partners Master Fund LP and Icahn Partners LP (the “Icahn Complainants”), captioned High River Ltd. P’ship v. Occidental Petroleum Corp., C.A. No. 2019-0403-JRS, seeking inspection of Occidental’s books and records pursuant to Section 220 of the Delaware General Corporation Law. In the complaint, the Icahn Complainants noted that they had accumulated over $1.6 billion of Occidental Common Stock. On June 14, 2019, Occidental filed an answer to the complaint in the Court of Chancery of the State of Delaware. A trial was held on September 20, 2019, and the court dismissed the Icahn Complaint. The Icahn Complainants appealed and oral arguments occurred in February 2020.

In 2016, Occidental received payments from the Republic of Ecuador of approximately $1.0 billion pursuant to a November 2015 arbitration award for Ecuador’s 2006 expropriation of Occidental’s Participation Contract for Block 15. The awarded amount represented a recovery of 60% of the value of Block 15. In 2017, Andes Petroleum Ecuador Ltd. (Andes) filed a demand for arbitration, claiming it is entitled to a 40% share of the judgment amount obtained by Occidental. Occidental contends that Andes is not entitled to any of the amounts paid under the 2015 arbitration award because Occidental’s recovery was limited to Occidental’s own 60% economic interest in the block. The merits hearing is scheduled for May 2020. Occidental intends to vigorously defend against this claim in arbitration.

The ultimate outcome and impact of outstanding lawsuits, claims and proceedings on Occidental cannot be predicted. Management believes that the resolution of these matters will not, individually or in the aggregate, have a material adverse effect on Occidental’s Consolidated Balance Sheets. If unfavorable outcomes of these matters were to occur, future results of operations or cash flows for any particular quarterly or annual period could be materially adversely affected. Occidental’s estimates are based on information known about the legal matters and its experience in contesting, litigating and settling similar matters. 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. Taxable years through 2016 for U.S. federal income tax purposes have been audited by the U.S. Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program and subsequent taxable years are currently under review. Taxable years through 2009 have been audited for state income tax purposes. While a single foreign tax jurisdiction is open for 2002, all other significant audit matters in foreign jurisdictions have been resolved through 2010. 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.

For Anadarko, its taxable years through 2016 for U.S. federal and state income tax purposes have been audited by the IRS and respective state taxing authorities. There are outstanding significant audit matters in one foreign jurisdiction. During the course of the tax audit, disputes have arisen and other disputes may arise as to facts and matters of law. Other than the matter discussed below, Occidental believes that the resolution of these outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.

Anadarko received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. In September 2018, Anadarko received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting Anadarko’s refund claim. As a result, Anadarko filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018. The case is currently in the IRS appeals process. If the matter is not resolved in the IRS appeals process, Occidental expects to continue pursuing resolution in the U.S. Tax Court.

While Occidental believes it is entitled to this refund, in accordance with ASC 740’s guidance on the accounting for uncertain tax positions, as of December 31, 2019, Occidental has recorded no tax benefit on the tentative cash tax refund of

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MANAGEMENT’S DISCUSSION AND ANALYSIS

$881 million. As a result, should Occidental not ultimately prevail on the issue, there would be no additional tax expense recorded for financial statement purposes other than future interest. However, in that event Occidental would be required to repay approximately $925 million ($898 million federal and $27 million in state taxes) plus accrued interest of approximately $189 million. As a result, a liability for this amount has been recorded in deferred credits and other liabilities - other at December 31, 2019.  

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, 2019, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state, local and international laws and regulations related to improving or maintaining environmental quality. The laws that require or address environmental remediation, including Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and similar federal, state, local and international 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, 2019, Occidental participated in or monitored remedial activities or proceedings at 177 sites, which included 36 sites assumed through the Acquisition. The following table presents Occidental’s current and non-current environmental remediation liabilities as of December 31, 2019 and 2018, the current portion of which is included in accrued liabilities ($162 million in 2019 and $120 million in 2018) and the remainder in deferred credits and other liabilities - environmental remediation liabilities ($1.04 billion in 2019 and $762 million in 2018). Occidental continues to evaluate the remediation obligations assumed through the Acquisition.

Occidental’s environmental remediation sites are grouped into four categories: National Priorities List (NPL) sites listed or proposed for listing by the EPA on the CERCLA NPL and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

	2019			2018
millions, except number of sites	Number of Sites	Remediation Balance		Number of Sites	Remediation Balance
NPL sites	36	$	463	34	$	458
Third-party sites	74	311		68	168
Occidental-operated sites	17	154		14	115
Closed or non-operated Occidental sites	50	269		29	141
Total	177	$	1,197	145	$	882

As of December 31, 2019, Occidental’s environmental remediation liabilities exceeded $10 million each at 20 of the 177 sites described above, and 101 of the sites had liabilities from $0 to $1 million each. As of December 31, 2019, 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 — accounted for 94 percent of its liabilities associated with NPL sites. Seventeen of the 36 NPL sites are indemnified by Maxus.

Six of the 74 third-party sites — a Maxus-indemnified chrome site in New Jersey, a former copper mining and smelting operation in Tennessee, a former oil field, a landfill and a chemical plant in California, and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities — accounted for 75 percent of Occidental’s liabilities associated with these sites. Nine of the 74 third-party sites are indemnified by Maxus.

Five sites — oil and gas operations in Colorado and chemical plants in Kansas, Louisiana, New York and Texas — accounted for 67 percent of the liabilities associated with the Occidental-operated sites.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

Six other sites — a landfill in Western New York, a former refinery in Oklahoma, former chemical plants in California, Tennessee and Washington, and a closed coal mine in Pennsylvania — accounted for 64 percent of the liabilities associated with closed or non-operated Occidental sites.

Environmental remediation liabilities vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation. Based on current estimates, Occidental expects to expend funds corresponding to approximately 40 percent of the year end remediation balance over the next three to four years with the remainder over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those amounts currently recorded for environmental remediation for all of its environmental sites could be up to $1.1 billion.

MAXUS ENVIRONMENTAL SITES

When Occidental acquired Diamond Shamrock Chemicals Company (DSCC) in 1986, Maxus, 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.

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 remediation liability 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 accrued estimated environmental remediation liability does not consider any recoveries for indemnified costs. Occidental’s ultimate share of the estimated costs may be higher or lower than its accrued remediation liability, and is subject to final design plans and the resolution 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. In June 2018, Occidental filed a complaint under CERCLA in Federal District Court in the State of New Jersey against numerous potentially responsible parties for reimbursement of amounts incurred or to be incurred to comply with the AOC, the ROD or to perform other remediation activities at the Site.

In June 2017, the court overseeing the Maxus bankruptcy approved a Plan of Liquidation (Plan) to liquidate Maxus and create a trust to pursue claims against YPF, Repsol and others to satisfy claims by Occidental and other creditors for past and future cleanup and other costs. In July 2017, the court-approved Plan became final and the trust became effective. Among other responsibilities, the trust will pursue claims against YPF, Repsol and others and distribute assets to Maxus’ creditors in accordance with the trust agreement and Plan. In June 2018, the trust filed its complaint against YPF and Repsol in Delaware bankruptcy court asserting claims based upon, among other things, fraudulent transfer and alter ego. On February 15, 2019, the bankruptcy court denied Repsol’s and YPF’s motions to dismiss the complaint.

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:

millions	2019		2018		2017
Operating Expenses
Oil and Gas	$	178	$	91	$	62
Chemical	80		80		78
Marketing and Midstream	12		10		7
Total	$	270	$	181	$	147
Capital Expenditures
Oil and Gas	$	111	$	71	$	71
Chemical	34		23		18
Marketing and Midstream	4		2		3
Total	$	149	$	96	$	92
Remediation Expenses
Corporate	$	112	$	47	$	39

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS

GLOBAL INVESTMENTS

A portion of Occidental’s assets are located outside North America. The following table shows the geographic distribution of Occidental’s assets at December 31, 2019 at both the segment and consolidated level related to Occidental’s ongoing operations:

millions	Oil and Gas		Chemical		Marketing and Midstream		Corporate and Other		Total Consolidated
North America
United States	$	72,833	$	4,173	$	13,324	$	3,952	$	94,282
Canada	—		126		27		—		153
Middle East	3,748		—		3,634		—		7,382
Latin America	1,355		57		—		—		1,412
Africa and Other	—		5		70		6,026		6,101
Consolidated	$	77,936	$	4,361	$	17,055	$	9,978	$	109,330

For the year ended December 31, 2019, net sales outside North America totaled $4.6 billion, or approximately 22% 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. 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 property, plant, and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations (AROs) and capitalized interest, net of DD&A and any impairment charges. For assets acquired in a business combination, 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 useful 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. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether Occidental is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

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

46 OXY 2019 FORM 10-K

MANAGEMENT’S DISCUSSION AND ANALYSIS

deterministic or probabilistic methods are used for the estimation. Occidental has no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.

Several factors could change Occidental’s proved oil and gas reserves. For example, Occidental receives a share of production from PSCs to recover its costs and generally an additional share for profit. Occidental’s share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, Occidental’s net economic benefit from these contracts is greater at higher product prices. In other cases, particularly with long-lived properties, lower product prices may lead to a situation where production of a portion of proved reserves becomes uneconomical. For such properties, higher product prices typically result in additional reserves becoming economical. Estimation of future production and development costs is also subject to change partially due to factors beyond Occidental’s control, such as energy costs and inflation or deflation of oil field service costs. These factors, in turn, could lead to changes in the quantity of proved reserves. Additional factors that could result in a change of proved reserves include production decline rates and operating performance differing from those estimated when the proved reserves were initially recorded.

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

For impairment testing, unless prices are contractually fixed, Occidental uses observable forward strip prices for oil and natural gas prices when projecting future cash flows. Future operating and development costs are estimated using the current cost environment applied to expectations of future operating and development activities to develop and produce oil and gas reserves. Market prices for oil, natural gas and NGL have been volatile and may continue to be volatile in the future. Changes in global supply and demand, transportation capacity, currency exchange rates, and applicable laws and regulations, and the effect of changes in these variables on market perceptions could impact current forecasts. Future fluctuations in commodity prices could result in estimates of future cash flows to vary significantly.

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% increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $1.15 per barrel, which would increase or decrease pre-tax income by approximately $415 million annually at current production rates.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. Net capitalized costs attributable to unproved properties were $29.5 billion at December 31, 2019, and $1.0 billion at December 31, 2018. The 2019 amount is primarily related to the Acquisition. The unproved amounts are not subject to DD&A until they are classified as proved properties. Individually insignificant unproved properties are combined and amortized on a group basis based on factors such as lease terms, success rates, and other factors. If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. Occidental periodically reviews unproved properties for impairments; numerous factors are considered, including but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property or the adjacent property, geologists’ evaluation of the property and the remaining lease term for the property. Management’s assessment of the availability of funds for future activities and the current and projected political and regulatory climate in areas in which Occidental operates also impacts the timing of any impairment.

PROVED RESERVES

Occidental estimates its proved oil and gas reserves according to the definition of proved reserves provided by the SEC and FASB. This definition includes oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, government regulations, etc. (at prices and costs as of the date the estimates are made). Prices include consideration of price changes provided only by contractual arrangements, and do not include adjustments based on expected future conditions. For reserves information, see the Supplemental Information on Oil and Gas Exploration and Production Activities under Item 8 of this Form 10-K.

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Occidental’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting

OXY 2019 FORM 10-K 47

MANAGEMENT’S DISCUSSION AND ANALYSIS

and processing the hydrocarbons. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, development plans, reservoir performance, prices, economic conditions, and governmental restrictions as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volume of proved reserves could have a negative impact on DD&A and could result in property impairments.

FAIR VALUES

Occidental estimates fair-value of long-lived assets for impairment testing, assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, pension plan assets and initial measurements of AROs.

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value.

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. When estimating the fair values of assets acquired and liabilities assumed, Occidental must apply various assumptions.

FINANCIAL ASSETS AND LIABILITIES

Occidental utilizes the mid-point between bid and ask prices for valuing the majority of its financial 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 financial assets and liabilities carried at fair value, Occidental measures fair value using the following methods:

Ø Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1.

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

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

Ø Occidental values debt using market-observable information for debt instruments that are traded on secondary markets. For debt instruments that are not traded, the fair value is determined by interpolating the value based on debt with similar terms and credit risk.

NON-FINANCIAL ASSETS

Occidental uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When Occidental is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows, and the expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental liabilities 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 environmental remediation liability 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 its environmental remediation liabilities on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably

48 OXY 2019 FORM 10-K

MANAGEMENT’S DISCUSSION AND ANALYSIS

expected to achieve the remedial objective. Occidental periodically reviews its environmental remediation liabilities and adjusts them as new information becomes available. Occidental records environmental remediation liabilities 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. Presently none of its environmental remediation liabilities 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.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental remediation liabilities and the range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may vary from the initial estimate; (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 its environmental remediation liabilities 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 CERCLA NPL sites, Occidental’s environmental remediation liabilities 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 liabilities accordingly.

If Occidental were to adjust the balance of its environmental remediation liabilities based on the factors described above, the amount of the increase or decrease would be recognized in earnings. For example, if the balance were reduced by 10%, Occidental would record a pre-tax gain of $120 million. If the balance were increased by 10%, Occidental would record an additional remediation expense of $120 million.

INCOME TAXES

Occidental files various U.S. federal, state and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Occidental routinely assesses the realizability of its deferred tax assets. If Occidental concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Occidental recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). Occidental uses the flow-through method to account for its investment tax credits. See Note 12 - Income Taxes in the Notes to Consolidated Financial Statements.

LOSS CONTINGENCIES

Occidental is involved, in the normal course of business, in lawsuits, claims and other legal proceedings and audits. Occidental accrues reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, Occidental discloses, in aggregate, its exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. Occidental reviews its loss contingencies on an ongoing basis.

Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors. See “Lawsuits, Claims and Contingencies” for additional information.

SIGNIFICANT ACCOUNTING AND DISCLOSURE CHANGES

See Note 2 - Accounting and Disclosure Changes in the Notes to Consolidated Financial Statements.

OXY 2019 FORM 10-K 49

MANAGEMENT’S DISCUSSION AND ANALYSIS

SAFE HARBOR DISCUSSION REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA

Portions of this report contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and involve risks and uncertainties that could materially affect expected results of operations, liquidity, cash flows and business prospects. Words such as “estimate,” “project,” “predict,” “will,” “would,” “should,” “could,” “may,” “might,” “anticipate,” “plan,” “intend,” “believe,” “expect,” “aim,” “goal,” “target,” “objective,” “likely” or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Occidental does not undertake any obligation to update any forward-looking statements as a result of new information, future events, except as required by law. Factors that may cause Occidental’s results of operations and financial position to differ from expectations include the factors discussed in Item 1A, “Risk Factors” and elsewhere in this Annual Report on Form 10-K.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 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 $260 million for a $1 per barrel change in oil prices and $90 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 $185 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. 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.

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.

RISK MANAGEMENT

Occidental conducts its risk management activities for marketing and trading under the controls and governance of its 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 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 on various risk measures and a number of other policy and procedural controls.

FAIR VALUE OF MARKETING DERIVATIVE CONTRACTS

Occidental carries 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) millions	2020			2021 and 2022		2023 and 2024		2025 and thereafter		Total
Prices actively quoted	$	(63	)	$	—	$	—	$	—	$	(63	)
Prices provided by other external sources	36			8		1		1		46
Total	$	(27	)	$	8	$	1	$	1	$	(17	)

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QUANTITATIVE AND QUALITATIVE DISCLOSURES

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. As of December 31, 2019, and 2018, Occidental had approximately 6 Bcf and 5 Bcf of natural gas held in storage, respectively, and had cash-flow hedges for the forecast sales, to be settled by physical delivery, of approximately 3 Bcf and 4 Bcf of stored natural gas, respectively.

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% 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 mitigated on short notice. As a result of these controls, Occidental believes that the market risk of its trading activities is not reasonably likely to have a material adverse effect on its performance.  

INTEREST RATE RISK

GENERAL

Occidental acquired interest rate swap contracts in the Acquisition. Occidental pays a fixed interest rate and receives a floating interest rate indexed to three-month LIBOR. The swaps have an initial term of 30 years with mandatory termination dates in September 2020 through 2023 and a total notional amount of $1.475 billion as of December 31, 2019. In October 2019, $125 million of notional interest rate swaps were terminated. As of December 31, 2019, the fair value of the swaps of negative $1.4 billion net liability was offset by $104 million in posted cash collateral, resulting in a net $1.3 billion liability. A 25-basis point decrease in implied LIBOR rates over the term of the swaps would result in an additional liability of approximately $101 million on these swaps. In January and February 2020, Occidental extended September 2020 mandatory termination dates to September 2021 and September 2022 for swaps with a notional value of $500 million and $150 million, respectively.

As of December 31, 2019, Occidental had $4.5 billion of variable-rate debt outstanding. A 25-basis point increase in LIBOR interest rates would increase gross interest expense approximately $11 million per year.

As of December 31, 2019, Occidental had $34.3 billion of fixed-rate debt outstanding. A 25-basis point change in Treasury rates would change the fair value of the fixed-rate debt approximately $680 million.

TABULAR PRESENTATION OF INTEREST RATE RISK

The table below provides information about Occidental’s debt obligations. Debt amounts represent principal payments by maturity date including amounts assumed from the Acquisition except WES debt.

millions except percentages	U.S. Dollar Fixed-Rate Debt			U.S. Dollar Variable-Rate Debt			Total (a)
2020	$	—		$	—		$	—
2021	3,426			2,956			6,382
2022	3,214			1,500			4,714
2023	1,213			—			1,213
2024	3,898			—			3,898
Thereafter	21,126			68			21,194
Total	$	32,877		$	4,524		$	37,401
Weighted-average interest rate	4.09		%	3.15		%	3.98		%
Fair Value	$	34,260		$	4,535		$	38,795

^(a)  Excluded net unamortized debt premiums of $914 million and debt issuance cost of $125 million.

FOREIGN CURRENCY RISK

Occidental’s international 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 international oil and gas subsidiaries have the United States dollar as the functional currency. As of December 31, 2019, 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.

OXY 2019 FORM 10-K 51

QUANTITATIVE AND QUALITATIVE DISCLOSURES

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 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 over-the-counter 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 party would need to post. The aggregate fair value of derivative instruments with credit-risk-contingent features for which a net liability position existed at December 31, 2019 was $787 million (net of $169 million collateral), primarily related to acquired interest-rate swaps, and $68 million (net of $1 million of collateral) existed at December 31, 2018.

As of December 31, 2019, the substantial majority of the credit exposures were with investment grade counterparties. Occidental believes its exposure to credit-related losses at December 31, 2019, was not material and losses associated with credit risk have been insignificant for all years presented.

DERIVATIVE INSTRUMENTS HELD FOR NON-TRADING PURPOSES

As of December 31, 2019, Occidental had derivative instruments in place to reduce the price risk associated with future oil production of 350 thousand barrels per day. As of December 31, 2019, these derivative instruments were at a $68 million net derivative liability position.

The following table shows a sensitivity analysis based on both a 5% and 10% change in commodity prices and their effect on the net derivative liability position of $68 million at December 31, 2019:

millions except percentages
Percent change in commodity prices	Resulting net fair value position-asset (liability)				Change to fair value from December 31, 2019 position
+ 5%		$	(270	)		$	(202	)
- 5%		$	100			$	168
+ 10%		$	(525	)		$	(457	)
-10%		$	254			$	322

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FINANCIAL STATEMENTS INDEX

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	54
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	57
Consolidated Balance Sheets	58
Consolidated Statements of Operations	60
Consolidated Statements of Comprehensive Income	61
Consolidated Statements of Stockholders’ Equity	62
Consolidated Statements of Cash Flows	63
Notes to Consolidated Financial Statements	64
Note 1 - Summary of Significant Accounting Policies	64
Note 2 - Accounting and Disclosure Changes	73
Note 3 - The Acquisition	74
Note 4 - Acquisitions, Dispositions and Other Transactions	78
Note 5 - Revenue	80
Note 6 - Inventories	82
Note 7 - Long-term Debt	83
Note 8 - Lease Commitments	85
Note 9 - Derivatives	88
Note 10 - Environmental Liabilities and Expenditures	91
Note 11 - Lawsuits, Claims, Commitments and Contingencies	93
Note 12 - Income Taxes	94
Note 13 - Stockholders’ Equity	96
Note 14 - Stock-Based Incentive Plans	98
Note 15 - Retirement and Postretirement Benefit Plans	100
Note 16 - Investments and Related-Party Transactions	104
Note 17 - Fair Value Measurements	104
Note 18 - Industry Segments and Geographic Areas	105
Quarterly Financial Data (Unaudited)	108
Supplemental Oil and Gas Information (Unaudited)	109
Schedule II – Valuation and Qualifying Accounts	124

OXY 2019 FORM 10-K 53

FINANCIAL STATEMENTS REPORT

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Occidental Petroleum Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three year period ended December 31, 2019, and the related notes and financial statement schedule II - valuation and qualifying accounts (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Change in Accounting Principle

As discussed in Notes 2 and 8 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Codification Topic 842, Leases.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

54 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS REPORT

Evaluation of the environmental liability associated with the lower 8.3 miles of the Lower Passaic River site

As discussed in Notes 1 and 10 to the consolidated financial statements, the Company accrues a liability for estimated environmental remedial activities when it is probable a liability has been incurred and the amount of remediation costs can be estimated. As of December 31, 2019, the Company’s estimated environmental liabilities were $1.2 billion. The Company accrued a liability related to its estimated allocable share of the costs to perform the remedial activities required for the lower 8.3 miles of the Lower Passaic River site.

We identified the evaluation of the environmental liability associated with the lower 8.3 miles of the Lower Passaic River site as a critical audit matter. There was a high degree of subjective auditor judgment in applying and evaluating the results of our procedures. This is due to 1) possible changes to expected remedial activities to implement the proposed clean-up plan outlined in the Record of Decision (ROD) issued by the Environmental Protection Agency (EPA) and their estimated costs, and 2) possible changes to the Company’s estimated share of the remediation costs.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s environmental liability process to estimate the cost of remedial activities, and estimate the Company’s allocable share of the remediation costs. We evaluated the remedial activities and related cost assumptions used by the Company by comparing them against remedial activities and cost estimates provided by the EPA in the ROD. We compared certain design documentation provided by the Company to the EPA in order to identify potential differences between the design plan and the ROD and assessed the impact of any such differences on the remediation cost assumptions used by the Company to estimate the liability. We assessed the Company’s assumption for its allocable share of the remediation costs and analyzed publicly available data sources for information that might be contrary to the information used by the Company. We involved an environmental analysis professional with specialized skills and knowledge who assisted in reading correspondence between the Company and the EPA related to the design phase for this site to assess the Company’s remediation cost assumptions.

Assessment of the estimated proved oil and gas reserves on the determination of depreciation and depletion expense related to proved oil and gas properties

As discussed in Note 1 to the consolidated financial statements, the Company determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. Under this method, capitalized costs are amortized over total estimated proved reserves. For the year ended December 31, 2019, the Company recorded depreciation and depletion expense related to proved oil and gas properties of $5.0 billion.

We identified the assessment of the estimated proved oil and gas reserves on the determination of depreciation and depletion expense related to proved oil and gas properties as a critical audit matter. Complex auditor judgment was required to evaluate the Company’s estimate of total proved oil and gas reserves, which is a key input for the determination of depreciation and depletion expense. Estimating total proved oil and gas reserves requires the expertise of professional petroleum reservoir engineers. The estimate of proved oil and gas reserves is dependent upon timing of future estimated production, operating and capital cost assumptions and oil and gas prices inclusive of market differentials.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s depreciation and depletion process, including the estimation of proved oil and gas reserves. We evaluated the competence, capabilities, and objectivity of the internal engineering and technical staff who estimated the proved oil and gas reserves and the independent reservoir engineering specialists engaged by the Company. We analyzed and assessed the determination of depreciation and depletion expense for compliance with industry and regulatory standards. We assessed compliance of the methodology used by the Company’s engineering and technical staff to estimate proved oil and gas reserves with industry and regulatory standards. We read the findings of the independent reservoir engineering specialist’s review of the methods and procedures used by the Company in estimating the proved reserves for compliance with industry and regulatory standards. We compared the timing of future estimated production assumptions used by the Company’s engineering and technical staff to historical production rates. We evaluated the operating and capital cost assumptions used by the Company’s engineering and technical staff by comparing them to historical costs. We assessed the oil and gas prices, including relevant market differentials, used by the Company’s engineering and technical staff by comparing them to publicly available prices, adjusted for historical market differentials.

OXY 2019 FORM 10-K 55

FINANCIAL STATEMENTS REPORT

Evaluation of the fair value measurement of oil and gas properties acquired in the Anadarko Petroleum Corporation business combination

As discussed in Note 3 to the consolidated financial statements, on August 8, 2019, the Company acquired Anadarko Petroleum Corporation (Anadarko) in a business combination. As a result of the transaction, the Company acquired both proved and unproved oil and gas properties. The acquisition-date fair value for the oil and gas properties was $46.5 billion.

We identified the evaluation of the initial fair value measurement of the oil and gas properties acquired in the Anadarko transaction as a critical audit matter. The Company used a combination of valuation methodologies in estimating the initial fair value of acquired oil and gas properties which included market based data from similar transactions and an income approach. There was a high degree of subjectivity in evaluating results of the market based transaction values and the discounted cash flow models used in the income approach. The evaluation of market based transactions included determining which market transactions were most relevant to the Company’s acquisition of Anadarko’s oil and gas properties. In addition, the income approach utilized risk adjusted discounted cash flow models, which included several significant assumptions. The following key assumptions were used in the discounted cash flow models: estimated future commodities prices, reserve category risk adjustment factors, estimated future production, estimated future operating and capital costs and discount rate. Changes to the assumptions used could have a significant effect on the determination of the acquisition date fair values.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s acquisition-date valuation process to develop and analyze the key assumptions, as listed above, used to measure the initial fair value of the acquired oil and gas properties. We compared acres utilized in the market analysis to historical Anadarko property records. We compared estimated future production to Anadarko’s historical actual production volumes. We evaluated the estimated future operating and capital cost assumptions by comparing them to Anadarko’s historical costs. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in: 1) evaluating the Company’s discount rate, by comparing it to a discount rate range that was independently developed using publicly available market data for comparable entities, 2) evaluating the reserve category risk adjustment factors used by the Company by comparing them to third party publications of risk adjustment factors utilized by market participants, 3) evaluating benchmark commodity prices used by the Company in estimating future commodity prices by comparing the benchmark prices utilized to publicly disclosed projected commodity prices 4) for oil and gas properties valued using the income approach, developing an estimate of the oil and gas properties’ fair value using the oil and gas properties’ cash flow assumptions and an independently developed discount rate, and compared to the Company’s fair value estimate and 5) evaluating the Company’s initial measurement of fair value by comparing the Company’s estimated fair values for onshore undeveloped properties to a range of indicated values of recent similar market transactions using publicly available market data.

/s/ KPMG LLP

We have served as the Company’s auditor since 2002.

Houston, Texas

February 27, 2020

56 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS REPORT

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Occidental Petroleum Corporation:

Opinion on Internal Control Over Financial Reporting

We have audited Occidental Petroleum Corporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes and financial statement schedule II - valuation and qualifying accounts (collectively, the consolidated financial statements), and our report dated February 27, 2020 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Assessment of and Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. 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 of internal control over financial reporting 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.

Definition and Limitations of Internal Control Over Financial Reporting

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Houston, Texas

February 27, 2020

OXY 2019 FORM 10-K 57

FINANCIAL STATEMENTS

Consolidated Balance Sheets Occidental Petroleum Corporation and Subsidiaries

	December 31,
millions	2019			2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,032		$	3,033
Restricted cash and restricted cash equivalents	480			—
Trade receivables, net of reserves of $19 in 2019 and $21 in 2018	6,373			4,893
Inventories	1,447			1,260
Assets held for sale	6,026			—
Other current assets	1,323			746
Total current assets	18,681			9,932
INVESTMENTS IN UNCONSOLIDATED ENTITIES	6,389			1,680
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment	105,881			58,799
Chemical segment	7,172			7,001
Marketing and midstream segment	8,176			8,070
Corporate	1,118			550
	122,347			74,420
Accumulated depreciation, depletion and amortization	(41,878		)	(42,983		)
	80,469			31,437
OPERATING LEASE ASSETS	1,385			—
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	2,406			805
TOTAL ASSETS	$	109,330		$	43,854

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

58 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS

Consolidated Balance Sheets Occidental Petroleum Corporation and Subsidiaries

	December 31,
millions except share and per-share amounts	2019			2018
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt	$	51		$	116
Current operating lease liabilities	569			—
Accounts payable	7,017			4,885
Accrued liabilities	5,302			2,411
Liabilities of assets held for sale	2,010			—
Total current liabilities	14,949			7,412
LONG-TERM DEBT, NET
Long-term debt, net	38,537			10,201
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes, net	9,717			907
Asset retirement obligations	4,385			1,424
Pension and postretirement obligations	1,807			809
Environmental remediation liabilities	1,035			762
Operating lease liabilities	854			—
Other	3,814			1,009
	21,612			4,911
EQUITY
Preferred stock, at $1.00 per share par value (100,000 shares at December 31, 2019)	9,762			—
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, issued shares: 2019 — 1,044,434,893 and 2018 — 895,115,637	209			179
Treasury stock: 2019 — 150,323,151 shares and 2018 — 145,726,051 shares	(10,653		)	(10,473		)
Additional paid-in capital	14,955			8,046
Retained earnings	20,180			23,750
Accumulated other comprehensive loss	(221		)	(172		)
Total stockholders’ equity	34,232			21,330
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	109,330		$	43,854

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

OXY 2019 FORM 10-K 59

FINANCIAL STATEMENTS

Consolidated Statements of Operations Occidental Petroleum Corporation and Subsidiaries

	Years Ended December 31,
millions except per-share amounts	2019			2018			2017
REVENUES AND OTHER INCOME
Net sales	$	20,393		$	17,824		$	12,508
Interest, dividends and other income	217			136			99
Gains on sale of equity investments and other assets, net	622			974			667
Total	21,232			18,934			13,274
COSTS AND OTHER DEDUCTIONS
Oil and gas operating expense	3,246			2,761			2,427
Transportation expense	621			152			175
Chemical and midstream cost of sales	2,791			2,833			2,938
Purchased commodities	1,679			822			54
Selling, general and administrative	882			585			546
Other operating and non-operating expense	1,425			1,028			878
Depreciation, depletion and amortization	5,981			3,977			4,002
Asset impairments and other charges	1,361			561			545
Taxes other than on income	707			439			311
Anadarko acquisition-related costs	1,647			—			—
Exploration expense	246			110			82
Interest and debt expense, net	1,066			389			345
Total	21,652			13,657			12,303
Income (loss) before income taxes and other items	(420		)	5,277			971
OTHER ITEMS
Gains on interest rate swaps and warrants, net	233			—			—
Income from equity investments	373			331			357
Total	606			331			357
Income from continuing operations before income taxes	186			5,608			1,328
Income tax expense	(693		)	(1,477		)	(17		)
Income (loss) from continuing operations	(507		)	4,131			1,311
Loss from discontinued operations, net of tax	(15		)	—			—
NET INCOME (LOSS)	(522		)	4,131			1,311
Less: Net income attributable to noncontrolling interest	(145		)	—			—
Less: Preferred stock dividends	(318		)	—			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(985	)	$	4,131		$	1,311
PER COMMON SHARE
Income (loss) from continuing operations—basic	$	(1.20	)	$	5.40		$	1.71
(Loss) from discontinued operations—basic	(0.02		)	—			—
Net income (loss) attributable to common stockholders—basic	$	(1.22	)	$	5.40		$	1.71
Income (loss) from continuing operations—diluted	$	(1.20	)	$	5.39		$	1.70
(Loss) from discontinued operations—diluted	(0.02		)	—			—
Net income (loss) attributable to common stockholders—diluted	$	(1.22	)	$	5.39		$	1.70
DIVIDENDS PER COMMON SHARE	$	3.14		$	3.10		$	3.06

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

60 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS

Consolidated Statements of Comprehensive Income Occidental Petroleum Corporation and Subsidiaries

	Years Ended December 31,
millions	2019			2018			2017
Net income (loss)	$	(522	)	$	4,131		$	1,311
Other comprehensive income (loss) items:
Foreign currency translation gains	—			—			3
Unrealized gains (losses) on derivatives (a)	(129		)	(6		)	13
Pension and postretirement gains (losses) (b)	78			137			(7		)
Reclassification of realized losses (gains) on derivatives (c)	2			13			(1		)
Other comprehensive income (loss), net of tax	(49		)	144			8
Comprehensive income (loss)	(571		)	4,275			1,319
Less: Comprehensive income attributable to noncontrolling interests	(145		)	—			—
Comprehensive income (loss) attributable to preferred and common stockholders	$	(716	)	$	4,275		$	1,319

^(a)  Net of tax of $36, $2 and $(7) in 2019, 2018 and 2017, respectively.

^(b)  Net of tax of $(25), $(38) and $4 in 2019, 2018 and 2017, respectively. See Note 15 - Retirement and Postretirement Benefit Plans in the Notes to Consolidated Financial Statements for additional information.

^(c)  Net of tax of $0, $(4) and $0 in 2019, 2018 and 2017, respectively.

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

OXY 2019 FORM 10-K 61

FINANCIAL STATEMENTS

Consolidated Statements of Stockholders’ Equity Occidental Petroleum Corporation and Subsidiaries

			Equity Attributable to Common Stock
millions, except per share amounts	Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Non-controlling Interests			Total Equity
Balance, December 31, 2016	$	—	$	178	$	(9,143	)	$	7,747	$	22,981		$	(266	)	$	—		$	21,497
Net income	—		—		—			—		1,311			—			—			1,311
Other comprehensive income, net of tax	—		—		—			—		—			8			—			8
Dividends on common stock, $3.06 per share	—		—		—			—		(2,357		)	—			—			(2,357		)
Issuance of common stock and other, net	—		1		—			137		—			—			—			138
Purchases of treasury stock	—		—		(25		)	—		—			—			—			(25		)
Balance, December 31, 2017	$	—	$	179	$	(9,168	)	$	7,884	$	21,935		$	(258	)	$	—		$	20,572
Net income	—		—		—			—		4,131			—			—			4,131
Other comprehensive income, net of tax	—		—		—			—		—			144			—			144
Dividends on common stock, $3.10 per share	—		—		—			—		(2,374		)	—			—			(2,374		)
Issuance of common stock and other, net	—		—		—			162		—			—			—			162
Purchases of treasury stock	—		—		(1,305		)	—		—			—			—			(1,305		)
Reclassification of stranded tax effects (See Note 2)	—		—		—			—		58			(58		)	—			—
Balance, December 31, 2018	$	—	$	179	$	(10,473	)	$	8,046	$	23,750		$	(172	)	$	—		$	21,330
Net income (loss)	—		—		—			—		(667		)	—			145			(522		)
Other comprehensive loss, net of tax	—		—		—			—		—			(49		)	—			(49		)
Dividends on common stock, $3.14 per share	—		—		—			—		(2,585		)	—			—			(2,585		)
Dividends on preferred stock, $3,489 per share	—		—		—			—		(318		)	—			—			(318		)
Issuance of common stock, net	—		30		—			6,909		—			—			—			6,939
Issuance of preferred stock	9,762		—		—			—		—			—			—			9,762
Purchases of treasury stock	—		—		(180		)	—		—			—			—			(180		)
Fair value of noncontrolling interest acquired	—		—		—			—		—			—			4,895			4,895
Noncontrolling interest distributions, net	—		—		—			—		—			—			(131		)	(131		)
Change in control WES	—		—		—			—		—			—			(4,909		)	(4,909		)
Balance, December 31, 2019	$	9,762	$	209	$	(10,653	)	$	14,955	$	20,180		$	(221	)	$	—		$	34,232

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

62 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS

Consolidated Statements of Cash Flows Occidental Petroleum Corporation and Subsidiaries

	Years Ended December 31,
millions	2019			2018			2017
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	(522	)	$	4,131		$	1,311
Adjustments to reconcile net income (loss) to net cash from operating activities:
Discontinued operations, net	15			—			—
Depreciation, depletion and amortization of assets	5,981			3,977			4,002
Deferred income tax (benefit) provision	(1,027		)	371			(719		)
Other noncash charges to income	940			34			219
Asset impairments and other charges	1,328			561			545
Gain on sales of equity investments and other assets, net	(622		)	(974		)	(667		)
Undistributed earnings from affiliates	(50		)	(43		)	(68		)
Dry hole expense	89			56			51
Changes in operating assets and liabilities:
Increase in receivables	(44		)	(740		)	(158		)
Decrease (increase) in inventories	77			(108		)	(349		)
Decrease in other current assets	186			94			39
(Decrease) increase in accounts payable and accrued liabilities	793			195			(89		)
Increase in current domestic and foreign income taxes	59			38			64
Other operating, net	—			77			680
Operating cash flow from continuing operations	7,203			7,669			4,861
Operating cash flow from discontinued operations, net of taxes	172			—			—
Net cash provided by operating activities	7,375			7,669			4,861
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures	(6,355		)	(4,975		)	(3,599		)
Change in capital accrual	(282		)	55			122
Purchase of businesses and assets, net	(28,088		)	(928		)	(1,064		)
Proceeds from sale of assets and equity investments, net	6,143			2,824			1,403
Equity investments and other, net	(291		)	(182		)	59
Investing cash flow from continuing operations	(28,873		)	(3,206		)	(3,079		)
Investing cash flow from discontinued operations	(154		)	—			—
Net cash used by investing activities	(29,027		)	(3,206		)	(3,079		)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt, net - Occidental	21,557			978			—
Payments of long-term debt, net - Occidental	(6,959		)	(500		)	—
Proceeds from long-term debt, net - WES	1,459			—			—
Payments of long-term debt, net - WES	(1,000		)	—			—
Proceeds from issuance of common and preferred stock	10,028			33			28
Purchases of treasury stock	(237		)	(1,248		)	(25		)
Cash dividends paid	(2,624		)	(2,374		)	(2,346		)
Distributions to noncontrolling interest	(257		)	—			—
Other financing, net	229			9			—
Financing cash flow from continuing operations	22,196			(3,102		)	(2,343		)
Financing cash flow from discontinued operations	(3		)	—			—
Net cash provided (used) by financing activities	22,193			(3,102		)	(2,343		)
Increase (decrease) in cash, cash equivalents, restricted cash and restricted cash equivalents	541			1,361			(561		)
Cash and cash equivalents — beginning of year	3,033			1,672			2,233
Cash, cash equivalents, restricted cash and restricted cash equivalents — end of year	$	3,574		$	3,033		$	1,672

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

OXY 2019 FORM 10-K 63

FINANCIAL STATEMENTS FOOTNOTES

Notes to Consolidated Financial Statements Occidental Petroleum Corporation and Subsidiaries

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

In this report, “Occidental” means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental conducts its operations through various subsidiaries and affiliates. On August 8, 2019, pursuant to the Agreement and Plan of Merger, dated as of May 9, 2019 (the Merger Agreement), among Occidental, Baseball Merger Sub 1, Inc., a Delaware corporation and an indirect, wholly owned subsidiary of Occidental (Merger Subsidiary), and Anadarko Petroleum Corporation (Anadarko), Occidental acquired all of the outstanding shares of Anadarko through a transaction in which Merger Subsidiary merged with and into Anadarko (the Acquisition), with Anadarko continuing as the surviving entity and as an indirect, wholly owned subsidiary of Occidental. See Note 3 - The Acquisition.

Occidental’s principal businesses consist of three reporting segments: oil and gas, chemical and marketing and midstream. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The marketing and midstream segment purchases, markets, gathers, processes, transports and stores oil, condensate, NGL, natural gas, carbon dioxide (CO₂) and power. It also trades around its assets, including transportation and storage capacity, and invests in entities that conduct similar activities. Included in the marketing and midstream segment is Occidental’s equity method investment in Western Midstream Partners, L.P. (WES). WES owns gathering systems, plants and pipelines and earns revenue from fee-based and service-based contracts with Occidental and third parties. Also within the marketing and midstream segment is Oxy Low Carbon Ventures (OLCV). OLCV seeks to capitalize on Occidental’s enhanced oil recovery (EOR) leadership by developing carbon capture, utilization and storage projects that source anthropogenic CO₂ and promote innovative technologies that drive cost efficiencies and economically grow Occidental’s business while reducing emissions.

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, variable interest entities (VIE) for which Occidental is the primary beneficiary, 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, statements of operations and statements of cash flows.

The Acquisition introduced different revenue and expense streams to Occidental’s legacy operations. As a result, changes were made to the structure of certain financial statements, notes and supplementary data to provide clarity and to conform to the current presentation.

WES INVESTMENT

WES is a publicly traded limited partnership with its common units traded on the New York Stock Exchange (NYSE) under the ticker symbol “WES.” WES owns the entire non-economic general partner interest and a 98% limited partner interest in Western Midstream Operating, LP (WES Operating), a Delaware limited partnership formed by Anadarko in 2007 to acquire, own, develop and operate midstream assets. WES maintains its own capital structure that is separate from Occidental, consisting of its own debt instruments and publicly traded common units.

From the Acquisition date through December 31, 2019, WES was determined to be a VIE, and Occidental, through its ownership of the general partner interest in WES, had the power to direct the activities that significantly affected the economic performance of WES and the obligation to absorb losses or the right to receive benefits that could be significant to WES. As such, Occidental was considered the primary beneficiary and consolidated WES and its consolidated subsidiaries from the date of the Acquisition to December 31, 2019. All intercompany transactions were eliminated during the consolidated period. Revenues of $1.1 billion, cost of sales of $500 million and operating cash flows of $498 million from the date of the Acquisition to December 31, 2019 are attributable to WES and are included in Occidental’s consolidated financial statements. Net income from noncontrolling interest for the same period relates to the 44.6% limited partner interest of WES owned by the public.

64 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

On December 31, 2019, Occidental and WES executed several agreements to allow WES to operate as an independent midstream company to support its ongoing pursuit of third-party growth opportunities. The executed agreements include amendments to the partnership agreement that significantly expand the unaffiliated limited partner unitholders’ rights. The significant amendments to the partnership agreement included:

Ø Providing for a simple majority of the unaffiliated unitholders to remove and elect a new general partner;

Ø Allowing for 20% of the unaffiliated unitholders to call a special meeting to vote to remove the general partner;

Ø Eliminating ownership thresholds that could have prevented unaffiliated unitholders from voting;

Ø Limiting Occidental’s voting percentage to 45% for certain unitholder matters until Occidental owns less than 40% of the limited partner units for twelve consecutive months; and

Ø Transferring 2% of Occidental’s limited partner interest to the general partner to provide a 2% economic interest to the general partner.

In addition to the partnership agreement amendments, in December 2019, the WES management team’s employment was transferred from Occidental to WES, and WES-dedicated personnel were seconded to WES from Occidental. The seconded employees’ employment is contractually obligated to be transferred to WES during 2020 once employee benefit plans are established. Additionally, as of December 31, 2019, Occidental employees no longer comprise a majority of the board of directors of WES’s general partner.

As a result of the partnership agreement amendments and other related agreements, WES no longer met the criteria to be considered a VIE. Accordingly, Occidental evaluated WES under the voting interest model and determined, because Occidental did not control the power to appoint or remove a successor general partner, it should no longer consolidate WES.

As a result of the loss of control, Occidental derecognized all assets, liabilities, and noncontrolling interest that were previously consolidated. Occidental recognized, at fair value, an equity method investment of $5.1 billion based on the closing market price of WES as of December 31, 2019 and recognized a loss of approximately $1 billion that is included in asset impairments and other charges on the Statement of Operations. In future periods, Occidental will recognize equity method earnings and dividends received for its economic interest in WES.

As of December 31, 2019, Occidental has a 55.4% unit ownership in WES, which consists of a 2% non-voting general partner unit interest and 54.5% of limited partner unit interest. In addition, Occidental has a 2% non-voting limited partner interest in WES Operating, which brings Occidental’s total effective economic interest in WES and its subsidiaries to 56.3%. During 2020, Occidental intends to reduce its limited partner ownership interest in WES to below 50%. Occidental’s historical pro rata interest in the net assets of WES was $1.9 billion, resulting in a basis difference of $3.2 billion primarily associated with WES’s equity method investments, PP&E, equity method goodwill and intangible assets - customer relationships and subject to amortization over their estimated average useful life.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates for 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.

DISCONTINUED OPERATIONS

In connection with the Acquisition, Occidental agreed to sell to TOTAL S.A. (Total) all of the assets, liabilities, businesses, and operations of Anadarko’s operations in Algeria, Ghana, Mozambique and South Africa (collectively, the Africa Assets) for $8.8 billion, subject to certain purchase price adjustments. In August 2019, a purchase and sale agreement was executed for these Africa Assets. This transaction is conditioned on the receipt of required regulatory approvals, as well as other customary closing conditions. In September 2019, Occidental completed the sale of Mozambique LNG assets to Total for $4.2 billion. The assets and liabilities for Algeria, Ghana and South Africa are presented as held for sale at December 31, 2019. The results of operations of the Africa Assets are presented as discontinued operations, see Note 4 - Acquisitions, Dispositions and Other Transactions. In January 2020, Occidental completed the sale of South Africa assets to Total.

Unless otherwise indicated, information presented in the Notes to the Consolidated Financial Statements relates only to Occidental’s continuing operations. Information related to discontinued operations is included in Note 4 - Acquisitions, Dispositions and Other Transactions, and in some instances, where appropriate, is included as a separate disclosure within the individual Notes to the Consolidated Financial Statements.

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FINANCIAL STATEMENTS FOOTNOTES

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with GAAP requires Occidental’s management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements. Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets 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 $14.9 billion as of December 31, 2019, and net sales of approximately $4.6 billion for the year ended December 31, 2019, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that have experienced political instability, nationalizations, corruption, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions, all of which increase Occidental’s risk of loss, 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 EQUIVALENTS AND RESTRICTED CASH EQUIVALENTS

Occidental considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents. The cash equivalents and restricted cash equivalents balance at December 31, 2019, included investments in government money market funds in which the carrying value approximates fair value.

The following table provides a reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents as reported at the end of the period in the Consolidated Statements of Cash Flows for the twelve months ended December 31, 2019 to the line items within the Consolidated Balance Sheet at December 31, 2019. There was no restricted cash or restricted cash equivalents at December 31, 2018.

millions	December 31, 2019
Cash and cash equivalents	$	3,032
Restricted cash and restricted cash equivalents	480
Cash and restricted cash included in assets held for sale	8
Restricted cash and restricted cash equivalents included in long-term receivables and other assets, net	54
Cash, cash equivalents, restricted cash, and restricted cash equivalents	$	3,574

Total restricted cash and restricted cash equivalents are primarily associated with a benefits trust for former Anadarko employees, payments of future hard-minerals royalties conveyed, and a judicially-controlled account related to a Brazilian tax dispute.

RECEIVABLES AND OTHER CURRENT ASSETS

Trade receivables, net, of $6.4 billion and $4.9 billion at December 31, 2019, and 2018, respectively, represent rights to payment for which Occidental has satisfied its obligations under a contract with a customer and its right to payment is conditioned only on the passage of time.

Other current assets included amounts receivable from working interest partners in Occidental’s oil and gas operations, derivative assets, and taxes receivable.

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FINANCIAL STATEMENTS FOOTNOTES

INVENTORIES

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

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

PROPERTY, PLANT AND EQUIPMENT

OIL AND GAS

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and 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. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether Occidental is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

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

millions	2019			2018			2017
Balance — beginning of year	$	112		$	108		$	56
Exploratory well costs acquired through the Acquisition	231			—			—
Additions to capitalized exploratory well costs pending the determination of proved reserves	383			220			201
Reclassifications to property, plant and equipment based on the determination of proved reserves	(230		)	(198		)	(128		)
Capitalized exploratory well costs charged to expense	(72		)	(18		)	(21		)
Balance — end of year	$	424		$	112		$	108

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 leasehold 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.

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FINANCIAL STATEMENTS FOOTNOTES

Occidental performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to prolonged declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include future production and timing of production, estimates of future product prices, contractual prices, estimates of risk-adjusted oil and gas reserves and estimates of future operating and development costs. See Note 17 - Fair Value Measurements and below for further discussion of asset impairments.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. Net capitalized costs attributable to unproved properties were $29.5 billion at December 31, 2019 and $1.0 billion December 31, 2018. The unproved amounts are not subject to DD&A until they are classified as proved properties. Individually insignificant unproved properties are combined and amortized on a group basis based on factors such as lease terms, success rates, and other factors. If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. Occidental periodically reviews unproved properties for impairments; numerous factors are considered, including but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property or the adjacent property, geologists’ evaluation of the property and the remaining lease term for the property. Management’s assessment of the availability of funds for future activities and the current and projected political and regulatory climate in areas in which Occidental operates also impacts the timing of any impairment.

CHEMICAL

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

Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are affected by domestic and international 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.

MARKETING AND MIDSTREAM

Occidental’s marketing and midstream 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 marketing and midstream 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.

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FINANCIAL STATEMENTS FOOTNOTES

GOODWILL

Occidental recognized goodwill of $5.8 billion associated with the Acquisition. The goodwill was based on WES’s publicly traded units and was primarily associated with the relationship between Occidental and WES as well as Occidental’s tax basis in WES. Upon loss of control and application of the equity method of accounting, $4.6 billion of goodwill was derecognized. The remaining $1.2 billion in goodwill is assigned to the marketing and midstream segment and is attributable to the deferred tax liability associated with the investment in WES.

Goodwill is subject to annual impairment testing every October. Occidental’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is likely impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill, Occidental will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures.

IMPAIRMENTS AND OTHER CHARGES

During 2019, Occidental’s Oil and Gas segment recognized pre-tax impairment and related charges of $285 million related to domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and $39 million related to Occidental’s mutually agreed early termination of its Qatar Idd El Shargi South Dome (ISSD) contract.

During 2018, Occidental recognized pre-tax impairment and related charges of $416 million related to Qatar Idd El Shargi North Dome (ISND) and ISSD proved properties and inventory. The fair value of the proved properties was measured based on the income approach, which 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, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk-adjusted discount rate of 10%. These inputs are categorized as Level 3 in the fair-value hierarchy.

Also in 2018, the marketing and midstream segment incurred approximately $100 million of charges primarily for lower of cost or market adjustments on its crude inventory and line fill.

In 2017, Occidental recorded net impairment and related charges of $397 million related to proved and unproved non-core Permian acreage and $120 million related to idled marketing and midstream facilities.

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

FAIR VALUES - RECURRING

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

Ø Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1.

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

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

Ø Occidental values debt using market-observable information for debt instruments that are traded on secondary markets. For debt instruments that are not traded, the fair value is determined by interpolating the value based on debt with similar terms and credit risk.

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FINANCIAL STATEMENTS FOOTNOTES

NON-FINANCIAL ASSETS

Occidental uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When Occidental is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows, and the expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions.

ACCRUED LIABILITIES - CURRENT

Accrued liabilities - current included accrued payroll, commissions and related expenses of $1.2 billion and $428 million at December 31, 2019, and 2018, respectively. Dividends payable, also included in accrued liabilities - current, were $884 million and $600 million at December 31, 2019, and 2018, respectively. Derivate financial instruments, also included in accrued liabilities - current, were $641 million and $134 million at December 31, 2019, and 2018, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental liabilities 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 environmental remediation liability 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 its environmental remediation liabilities 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 its environmental remediation liabilities and adjusts them as new information becomes available. Occidental records environmental remediation liabilities 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. Presently none of its environmental remediation liabilities 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.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental remediation liabilities and the range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may vary from the initial estimate; (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 its environmental remediation liabilities at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental’s environmental remediation liabilities 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 environmental remediation liabilities accordingly.

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FINANCIAL STATEMENTS FOOTNOTES

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, 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 obligations changes, Occidental records an adjustment to both the asset retirement obligations 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.

The majority of Occidental’s asset retirement obligations relate to the plugging of wells and the related abandonment of oil and gas properties. Revisions in estimated liabilities during the period primarily relate to liabilities acquired in the Acquisition and include, but are not limited to, changes in estimates of asset retirement costs, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlements.

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 asset retirement obligations for the years ended December 31,:

millions	2019			2018
Beginning balance	$	1,499		$	1,312
Liabilities assumed in the Acquisition	3,344			—
Liabilities incurred – capitalized to PP&E	131			31
Liabilities settled and paid	(200		)	(40		)
Accretion expense	71			67
Acquisitions, dispositions and other	—			(18		)
WES loss of control	(359		)	—
Revisions to previous estimates	147			147
Ending balance (a)	$	4,633		$	1,499

^(a)  The ending balance included $248 million and $75 million related to the current balance of AROs that are included in Accrued Liabilities on the Consolidated Balance Sheets at December 31, 2019 and 2018, respectively.

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 carrying value 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 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 operations. There were no fair value hedges as of and during the years ended December 31, 2019, 2018 and 2017.

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% of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. Occidental discontinues hedge accounting when it determines that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

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FINANCIAL STATEMENTS FOOTNOTES

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 14 - Stock-Based Incentive Plans. 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 (RSU), cash return on capital employed incentive awards (CROCEI), return on capital employed incentive awards (ROCEI) and return on assets incentive awards (ROAI), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout at the grant date. For total shareholder return incentive awards (TSRI), compensation value is initially measured on the grant date using estimated payout levels derived from a Monte Carlo valuation model. Compensation expense for RSUs, CROCEIs, ROCEIs, ROAIs 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. Dividends accrued on unvested awards are adjusted quarterly for any changes in the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable. All such performance or stock-price-related changes are recognized in periodic compensation expense. The stock-settled portion of these awards is expensed using the initially measured compensation value. The liability resulting from the cash settled portion of these awards and accrued dividends are remeasured at each reporting period.

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, 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 15 - Retirement and Postretirement Benefit Plans, in its financial statements using a December 31 measurement date.

Occidental’s defined benefit pension and postretirement benefit plan obligations are actuarially determined 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 U.S. federal, state and foreign income taxes for continuing operations of approximately $1.7 billion, $1.1 billion and $0.8 billion during the years ended December 31, 2019, 2018 and 2017, respectively. Occidental received refunds of $79 million, $82 million and $768 million during the years ended December 31, 2019, 2018, and 2017, respectively. Occidental also paid production, property and other taxes of approximately $725 million, $505 million and $375 million during the years ended December 31, 2019, 2018 and 2017, respectively, substantially all of which was in the United States. Interest paid totaled $911 million, $383 million and $351 million, net of capitalized interest of $85 million, $46 million and $52 million, for the years 2019, 2018 and 2017, respectively.

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FINANCIAL STATEMENTS FOOTNOTES

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s international oil and gas operations is the U.S. dollar since cash flows are denominated principally in U.S. 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.

INCOME TAXES

Occidental files various U.S. federal, state, and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Occidental routinely assesses the realizability of its deferred tax assets. If Occidental concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Occidental recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). Occidental uses the flow-through method to account for its investment tax credits. See Note 12 - Income Taxes.

OTHER LOSS CONTINGENCIES

Occidental 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. Occidental or certain of its subsidiaries also are involved in proceedings under CERCLA and similar federal, state, local and international 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 Occidental 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 outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. In Note 10 - Environmental Liabilities and Expenditures, Occidental has disclosed its reserve balances for environmental remediation matters that satisfy this criteria. See Note 11 - Lawsuits, Claims, Commitments and Contingencies.

NOTE 2 - ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

In January 2019, Occidental adopted the new lease standard Accounting Standards Codification Topic 842 - Leases (ASC 842). The new standard requires Occidental to recognize most leases, including operating leases, on the balance sheet. The new rules require lessees to recognize a right-of-use (ROU) asset and lease liability for all leases with lease terms of more than 12 months. Occidental adopted the standard using the modified retrospective approach, including adopting several optional practical expedients. See Note 8 - Lease Commitments.

In February 2018, the Financial Accounting Standards Board (FASB) released standards that allow the reclassification from accumulated other comprehensive income to retained earnings of stranded tax effects resulting from changes to U.S. federal tax law from the 2017 Tax Cuts and Jobs Act (Tax Reform) enacted in December 2017. Occidental early adopted this standard in the first quarter of 2018, resulting in the reclassification of $58 million in stranded tax effects from accumulated other comprehensive income (AOCI) to retained earnings.

In January 2018, Occidental adopted the new revenue recognition standard Topic 606 - Revenue from Contracts with Customers and related updates (ASC 606). The new standard requires more detailed disclosures related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Occidental adopted the standard using the modified retrospective method. The cumulative-effect adjustment to retained earnings upon adoption was not material. See Note 5 - Revenue.

In January 2017, FASB issued new guidance clarifying the definition of a business under the topic Business Combinations. The rules became effective in the first quarter of 2018, and did not have a material impact to Occidental’s financial statements upon adoption.

OXY 2019 FORM 10-K 73

FINANCIAL STATEMENTS FOOTNOTES

NOTE 3 - THE ACQUISITION

On May 9, 2019, Occidental entered into the Acquisition Agreement with Anadarko. On August 8, 2019, Anadarko’s stockholders voted to approve the Acquisition and it was made effective the same day. The Acquisition added to Occidental’s oil and gas portfolio, primarily in the Permian Basin, DJ Basin and Gulf of Mexico, and a controlling interest in WES.

In exchange for each share of Anadarko common stock, Anadarko stockholders received $59.00 in cash and 0.2934 of a share of Occidental common stock, plus cash in lieu of any fractional share of Occidental common stock that otherwise would have been issued, based on the average price of $46.31 per share of Occidental common stock on the NYSE on August 8, 2019.

In connection with the Acquisition, Occidental issued $13.0 billion of new senior unsecured notes, $8.8 billion of term loans (the Term Loans) and 100,000 shares of series A preferred stock (the Preferred Stock) with a warrant to purchase 80 million shares of Occidental common stock at an exercise price of $62.50 (the Warrant) for $10 billion. In addition, Occidental increased its existing $3.0 billion revolving credit facility by an additional $2.0 billion in commitments. See Note 7 - Long-term Debt and Note 13 - Stockholders’ Equity for additional information.

The Acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. The following table presents the Acquisition consideration paid to Anadarko stockholders as a result of the Acquisition:

millions except per-share amounts	As of August 8, 2019
Total shares of Anadarko common stock eligible for Acquisition consideration		491.6
Cash consideration (per share of common stock and shares underlying Anadarko stock-based awards eligible for Acquisition consideration)		$	59.00
Cash portion of Acquisition consideration		$	29,002
Total shares of Anadarko common stock eligible for Acquisition consideration		491.6
Exchange ratio (per share of Anadarko common stock)		0.2934
Total shares of Occidental common stock issued to Anadarko stockholders		144
Average share price of Occidental common stock at August 8, 2019		$	46.31
Stock portion of Acquisition consideration		$	6,679
Acquisition consideration attributable to Anadarko stock-based awards		$	23
Total Acquisition consideration		$	35,704

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FINANCIAL STATEMENTS FOOTNOTES

The following table sets forth the preliminary allocation of the Acquisition consideration. Certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, final appraisals of certain assets acquired and liabilities assumed, valuation of pre-Acquisition contingencies and final tax returns that provide underlying tax basis of assets acquired and liabilities assumed. Occidental will finalize the purchase price allocation during the 12-month period following the Acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

millions	As of August 8, 2019
Fair value of assets acquired:
Current assets		$	3,596
Africa Assets held for sale		10,616
Investments in unconsolidated entities		194
Property, plant and equipment		49,074
Other assets		836
Amount attributable to assets acquired		$	64,316
Fair value of liabilities assumed:
Current liabilities		$	3,410
Liabilities of Africa Assets held for sale		2,200
Long-term debt		13,240
Deferred income taxes		8,607
Asset retirement obligations		2,724
Pension and post-retirement obligations		1,072
Non-current derivative liabilities		1,280
Other long-term liabilities		2,323
Amount attributable to liabilities assumed		$	34,856
Net assets		$	29,460
Fair value of WES net assets acquired less noncontrolling interests (a)		$	6,244
Total Acquisition consideration		$	35,704

^(a)  See Note 1 - Summary of Significant Accounting Policies for a discussion of the WES investment.

OXY 2019 FORM 10-K 75

FINANCIAL STATEMENTS FOOTNOTES

The following table summarizes the fair value of the major categories of WES assets acquired and liabilities assumed at the Acquisition date as well as the noncontrolling interest, which primarily consists of the 44.6% limited partner interest in WES owned by the public. The fair value of Occidental’s controlling interest in WES is calculated based on the market capitalization value at the Acquisition date.

millions	As of August 8, 2019
Fair value of WES assets acquired:
Current assets		$	499
Investments in unconsolidated entities		2,425
Property, plant and equipment		10,160
Intangible assets - customer relationships		1,800
Goodwill		5,772
Other assets		342
Amount attributable to assets acquired		$	20,998
Fair value of WES liabilities assumed:
Current liabilities		$	815
Long-term debt		7,407
Deferred income taxes		1,174
Asset retirement obligations		321
Other long-term liabilities		142
Amount attributable to liabilities assumed		$	9,859
Net assets		$	11,139
Less: Fair value of noncontrolling interests in WES		$	4,895
Fair value of WES net assets acquired less noncontrolling interests		$	6,244

The aggregate purchase price noted above was allocated to the major categories of assets and liabilities acquired based upon their preliminary estimated fair values at the date of the Acquisition. The valuation of certain assets, including property and intangible assets, are based on preliminary appraisals. The majority of measurements of assets acquired and liabilities assumed, other than debt, are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on both available market data and a cost approach.

Onshore undeveloped oil and gas properties were valued primarily using a market approach based on comparable transactions for similar properties while the income approach was utilized for developed oil and gas properties based on underlying reserve projections at the Acquisition date. For the acquired Gulf of Mexico offshore properties, an income approach was used as the primary valuation method based on underlying reserve projections. Income approaches are considered level 3 fair value estimates and include significant assumptions of future production, commodity prices, and operating and capital cost estimates, discounted using weighted average cost of capital for industry peers, and risk adjustment factors based on reserve category. Price assumptions were based on a combination of market information and published industry resources adjusted for historical differentials. Cost estimates were based on current observable costs inflated based on historical and expected future inflation. Taxes were based on current statutory rates.

The fair value of WES investments in unconsolidated entities were valued using an income approach for each investment, with significant inputs being forecasted distributions, an anticipated growth rate and an estimated discount rate. Acquired WES property, plant and equipment primarily consisted of gathering systems and processing and treating facilities and were primarily valued using a replacement cost approach. Intangible assets primarily consist of relationships with third-party customers, the fair value of which was determined using an income approach, including significant assumptions related to estimated cash flows from third-party customers less a contributory asset charge, a customer retention rate and an estimated discount rate. Customer relationships are amortized over 30 years. Goodwill is attributable to the difference in WES market capitalization value and the net assets acquired and primarily relates to the relationship between Occidental and WES that is not recognized as a separate asset, due to Occidental consolidating WES as of the Acquisition date.

Deferred income taxes represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. The measurement of debt instruments was based on unadjusted quoted prices in an active market and are primarily Level 1; approximately $2.5 billion of the assumed Anadarko debt is considered Level 2, while approximately $730 million of the WES debt is considered Level 2. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2.

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FINANCIAL STATEMENTS FOOTNOTES

With the completion of the Acquisition, Occidental acquired proved and unproved properties of approximately $19.1 billion and $27.4 billion, respectively, primarily associated with the Permian Basin, DJ Basin, Gulf of Mexico and Powder River Basin. The remaining $2.5 billion in PP&E which consists of non-oil and gas mineral interests and other real estate assets.

From the date of the Acquisition through December 31, 2019, revenues and the net loss attributable to common stockholders associated with the operations acquired through the Acquisition totaled $4.2 billion and $1.7 billion, respectively, which includes a charge as a result of recording Occidental’s investment in WES at fair value as of December 31, 2019 upon the loss of control.

The following table summarizes the unaudited pro forma condensed financial information of Occidental as if the Acquisition had occurred on January 1, 2018:

	Year ended December 31,
millions except per-share amounts	2019			2018
Revenues	$	28,723		$	31,206
Net income (loss) attributable to common stockholders (a)	$	(769	)	$	2,965
Net income (loss) attributable to common stockholders per share—basic	$	(0.95	)	$	3.26
Net income (loss) attributable to common stockholders per share—diluted	$	(0.95	)	$	3.25

^(a)  Excluding the pro-forma results of WES, net income (loss) attributable to common stockholders would be $(1.1) billion and $2.8 billion for the years ended December 31, 2019 and 2018, respectively.

The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Acquisition been completed at January 1, 2018, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma information for 2019 and 2018 is a result of combining the statements of operations of Occidental with the pre-Acquisition results from January 1, 2019, and 2018 of Anadarko and included adjustments for revenues and direct expenses. The pro forma results exclude results from the Africa Assets, any cost savings anticipated as a result of the Acquisition and the impact of any Acquisition-related costs. The pro forma results include adjustments to DD&A (depreciation, depletion and amortization) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest expense. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the Acquisition are properly reflected.

ANADARKO ACQUISITION-RELATED COSTS

The following table summarizes the Acquisition-related costs incurred for the year ended December 31:

millions	2019
Employee severance and related employee cost	$	1,033
Licensing fees for critical seismic data	401
Bank, legal, consulting and other	213
Total	$	1,647

Employee severance and related employee cost primarily relates to one-time severance costs and the accelerated vesting of certain Anadarko share-based awards for former Anadarko employees based on the terms of the Acquisition Agreement and existing change of control provisions within the former Anadarko employment agreements. In addition, employee severance and related employee cost included expenses for a voluntary separation program for eligible employees. Occidental initiated this program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the voluntary separation program were ongoing at December 31, 2019, with additional expenses associated with the program expected to be incurred through most of 2020. Employees may revoke their participation in the voluntary severance program up to their separation date.

The seismic licensing fees relate to relicensing of critical seismic data related to the Gulf of Mexico, Permian Basin and DJ Basin that Anadarko had licensed from third-party vendors. The third-party vendors who own the seismic data require a transfer fee in order for Occidental to use the data.

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FINANCIAL STATEMENTS FOOTNOTES

NOTE 4 - ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

AFRICA ASSETS - DISCONTINUED OPERATIONS

In September 2019, Occidental completed the sale of Mozambique LNG assets to Total for approximately $4.2 billion, with proceeds used to pay down a portion of the Term Loans. In January 2020, Occidental completed the sale of South Africa assets to Total. Occidental and Total continue to work toward completing the sales of the remaining Africa Assets. The carrying amount of the remaining Africa Assets will be adjusted in future periods based on changes in fair value. The results of the Africa Assets are presented as discontinued operations in the Consolidated Statements of Operations and Cash Flows.

The following table presents the amounts reported in discontinued operations, net of income taxes, related to the Africa Assets subsequent to the Acquisition closing date through December 31, 2019:

millions	2019
Revenues and other income
Net sales	$	739
Costs and other deductions
Oil and gas lease operating expense	$	81
Transportation expense	14
Taxes other than on income	133
Fair value adjustment on assets held for sale	244
Other	53
Total costs and other deductions	$	525
Income before income taxes	$	214
Income tax expense	(229		)
Discontinued operations, net of tax	$	(15	)

The following table presents amounts related to the Africa Assets reported as held for sale in the Consolidated Balance Sheet as of December 31, 2019:

millions	2019
Current assets	$	289
Property, plant and equipment, net	5,481
Long-term receivables and other assets, net	256
Assets held for sale (a)	$	6,026
Current liabilities	$	452
Long-term debt, net - finance leases	185
Deferred income taxes	1,112
Asset retirement obligations	181
Other	80
Liabilities of assets held for sale (a)	$	2,010
Net assets held for sale	$	4,016

^(a)  Assets and liabilities held for sale at December 31, 2019 included South Africa assets which were sold to Total in January 2020.

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FINANCIAL STATEMENTS FOOTNOTES

OTHER TRANSACTIONS

2019

In December 2019, Occidental disposed of real estate assets for $565 million. Occidental utilized net proceeds to pay down a portion of the Term Loans. Concurrent with the sale, Occidental entered a thirteen-year lease for part of the real estate assets. Based on the terms of the lease, Occidental treated this as a failed sale-leaseback, retained the related book value in property, plant and equipment and recognized a finance lease of approximately $300 million based on the discounted future minimum lease payments.

In November 2019, Occidental and Ecopetrol closed on the joint venture to develop approximately 97,000 net acres of Occidental’s Midland Basin unproved properties in the Permian Basin. Ecopetrol paid $750 million in cash at closing and up to $750 million of carried capital in exchange for a 49% interest in the new venture. Occidental recognized a gain of $563 million on the sale. Following the close, Occidental owned a 51% interest and operates the joint venture. During the carry period, Ecopetrol will pay 75% of Occidental’s share of capital expenditures, up to $750 million. The joint venture allows Occidental to accelerate its development plans in the Midland Basin, where it currently has minimal activity. Occidental will retain production and cash flow from its existing operations in the Midland Basin. The proceeds were used to pay down a portion of the Term Loans.

In September 2019, Occidental sold its remaining equity investment in Plains All American Pipeline, L.P. and Plains GP Holdings, L.P. (together, Plains) for net proceeds of $646 million, which resulted in a pre-tax gain of $114 million. The proceeds were used to pay down a portion of the Term Loans.

2018

In September 2018, Occidental divested non-core domestic midstream assets for total consideration of $2.6 billion, of which approximately $2.4 billion was received at closing, resulting in a pre-tax net gain of $907 million. These assets include the Centurion common carrier oil pipeline and storage system, Southeast New Mexico oil gathering system, and Ingleside Crude Terminal. Following the transactions, Occidental retained its long-term flow assurance, pipeline takeaway and export capacity through its retained marketing business.

In July 2018, Occidental acquired a previously leased power and steam cogeneration facility for $443 million.

In March 2018, Occidental divested non-core midstream assets for approximately $150 million, resulting in a pre-tax gain of $43 million.

2017

In the third quarter of 2017, Occidental closed on two divestitures of non-core acreage in the Permian Basin for proceeds of approximately $0.6 billion, resulting in a pre-tax gain of approximately $81 million. Concurrently, Occidental purchased additional ownership interests and assumed operatorship in CO₂ enhanced oil recovery (EOR) properties located in the Seminole-San Andres Unit for approximately $0.6 billion, which was primarily allocated to proved property. In the fourth quarter of 2017, Occidental sold other non-core proved and unproved acreage in the Permian Basin for approximately $90 million, resulting in a pre-tax gain of approximately $55 million. Occidental also classified approximately $0.5 billion in non-core proved and unproved Permian acreage to assets held for sale at December 31, 2017.

In April 2017, Occidental completed the sale of its South Texas operations for net proceeds of $0.5 billion resulting in pre-tax gain of $0.5 billion.

OXY 2019 FORM 10-K 79

FINANCIAL STATEMENTS FOOTNOTES

NOTE 5 - REVENUE

Revenue from customers is recognized when obligations under the terms of a contract are satisfied; this generally occurs with the delivery of oil, gas, NGL, chemicals or services such as transportation. Revenue from customers is measured as the amount of consideration Occidental expects to receive in exchange for the delivery of goods or services. Contracts may last from one month to one year or more, and may have renewal terms that extend indefinitely at the option of either party. Price is typically based on market indexes. Volumes fluctuate due to production and, in certain cases, customer demand and transportation availability. Occidental records revenue net of certain taxes, such as sales taxes, that are assessed by governmental authorities on Occidental’s customers.

Occidental does not incur significant costs to obtain contracts. Incidental items that are immaterial in the context of the contract are recognized as expenses. Sales of hydrocarbons and chemicals to customers are invoiced and settled on a monthly basis. Occidental is not usually subject to obligations for warranties, rebates, returns or refunds except in the case of customer incentive payments as discussed for the chemical segment below. Occidental does not typically receive payment in advance of satisfying its obligations under the terms of its sales contracts with customers; therefore, liabilities related to such payment are immaterial to Occidental.

OIL AND GAS SEGMENT

Revenue from oil and gas production is recognized when production is delivered and control passes to the customer. 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.

CHEMICALS SEGMENT

Revenue from chemical product sales is recognized when control passes 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. Customer incentives are estimated and recorded as a reduction to revenue ratably over the contract period. Such estimates are evaluated and revised as warranted. Revenue from exchange contracts is excluded from revenue from customers.

MARKETING AND MIDSTREAM SEGMENT

Revenue from pipeline and gas processing is recognized upon the completion of the transportation or processing service. Revenue from power sales is recognized upon delivery. Net marketing revenue is included in net sales, but excluded from revenue from customers in the table below. Net marketing revenue is recognized upon completion of contract terms that are a prerequisite to payment and upon title transfer for physical deliveries. Unless the normal purchases and sales exception has been elected, net marketing revenue is classified as a derivative, reported on a net basis, recorded at fair value and changes in fair value are reflected in net sales.

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FINANCIAL STATEMENTS FOOTNOTES

The following table reconciles revenue from customers to total net sales for the years ended December 31:

millions	2019		2018
Revenue from customers	$	18,674	$	15,560
All other revenues (a)	1,719		2,264
Net sales	$	20,393	$	17,824

^(a)  Included net marketing derivatives, oil collars and calls and chemical exchange contracts.

DISAGGREGATION OF REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table presents Occidental’s revenue from customers by segment, product and geographical area. The oil and gas segment typically sells its oil, gas and NGL at the lease or concession area. Chemical revenues are shown by geographic area based on the location of the sale. Marketing and midstream revenues are shown by the location of sale.

millions	United States			Middle East			Latin America		Other International		Eliminations			Total
Year ended December 31, 2019
Oil and Gas
Oil	$	8,411		$	2,758		$	683	$	—	$	—		$	11,852
NGL	658			263			—		—		—			921
Gas	424			319			20		—		—			763
Other	(1		)	(5		)	—		—		—			(6		)
Segment total	$	9,492		$	3,335		$	703	$	—	$	—		$	13,530
Chemical	$	3,858		$	—		$	155	$	67	$	—		$	4,080
Marketing and Midstream (a)
Gas processing	$	395		$	351		$	—	$	—	$	—		$	746
WES - Gas processing and pipeline	1,110			—			—		—		—			1,110
Power and other	472			—			—		—		—			472
Segment total	$	1,977		$	351		$	—	$	—	$	—		$	2,328
Eliminations	$	—		$	—		$	—	$	—	$	(1,264	)	$	(1,264	)
Consolidated	$	15,327		$	3,686		$	858	$	67	$	(1,264	)	$	18,674
Year ended December 31, 2018
Oil and Gas
Oil	$	5,125		$	3,405		$	715	$	—	$	—		$	9,245
NGL	430			261			—		—		—			691
Gas	185			294			16		—		—			495
Other	7			3			—		—		—			10
Segment total	$	5,747		$	3,963		$	731	$	—	$	—		$	10,441
Chemical	$	4,363		$	—		$	205	$	80	$	—		$	4,648
Marketing and Midstream
Gas processing	$	557		$	425		$	—	$	—	$	—		$	982
Pipelines	311			—			—		—		—			311
Power and other	108			—			—		—		—			108
Segment total	$	976		$	425		$	—	$	—	$	—		$	1,401
Eliminations	$	—		$	—		$	—	$	—	$	(930	)	$	(930	)
Consolidated	$	11,086		$	4,388		$	936	$	80	$	(930	)	$	15,560

^(a)  The marketing and midstream segment included revenues from customers from WES from the date of the Acquisition to December 31, 2019. See Note 1 - Summary of Significant Accounting Policies. 

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FINANCIAL STATEMENTS FOOTNOTES

TRANSACTION PRICE ALLOCATED TO REMAINING PERFORMANCE OBLIGATIONS

Revenue expected to be recognized from certain performance obligations that are unsatisfied as of December 31, 2019, is reflected in the table below. Occidental applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. As a result, the following table represents a small portion of Occidental’s expected future consolidated revenues, as future revenue from the sale of most products and services is dependent on future production or variable customer volume and variable commodity prices for that volume:

millions	Total
2020	$	103
2021	103
2022	7
2023	7
2024	7
Thereafter	53
Total	$	280

NOTE 6 - INVENTORIES

Finished goods primarily represents oil, which is carried at the lower of weighted-average cost or net realizable value, and caustic soda and chlorine, which are valued under the LIFO method. Net carrying values of inventories valued under the LIFO method were $168 million and $169 million at December 31, 2019 and 2018, respectively. Inventories consisted of the following at December 31:

millions	2019			2018
Raw materials	$	75		$	74
Materials and supplies	879			445
Commodity inventory and finished goods	533			788
	1,487			1,307
Revaluation to LIFO	(40		)	(47		)
Total	$	1,447		$	1,260

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FINANCIAL STATEMENTS FOOTNOTES

NOTE 7 - LONG-TERM DEBT

Long-term debt consisted of the following:

millions	December 31, 2019
4.850% senior notes due 2021		$	677
2.600% senior notes due 2021		1,500
4.100% senior notes due 2021		1,249
Variable rate bonds due 2021 (2.854% as of December 31, 2019)		500
Variable rate bonds due 2021 (3.151% as of December 31, 2019)		500
2-year variable rate Term Loan due 2021 (3.111% as of December 31, 2019)		1,956
2.700% senior notes due 2022		2,000
3.125% senior notes due 2022		814
2.600% senior notes due 2022		400
Variable rate bonds due 2022 (3.360% as of December 31, 2019)		1,500
2.700% senior notes due 2023		1,191
8.750% medium-term notes due 2023		22
2.900% senior notes due 2024		3,000
6.950% senior notes due 2024		650
3.450% senior notes due 2024		248
3.500% senior notes due 2025		750
5.550% senior notes due 2026		1,100
3.200% senior notes due 2026		1,000
3.400% senior notes due 2026		1,150
7.500% debentures due 2026		112
3.000% senior notes due 2027		750
7.125% debentures due 2027		150
7.000% debentures due 2027		48
6.625% debentures due 2028		14
7.150% debentures due 2028		235
7.200% senior debentures due 2028		82
7.200% debentures due 2029		135
7.950% debentures due 2029		116
8.450% senior debentures due 2029		116
3.500% senior notes due 2029		1,500
Variable rate bonds due 2030 (1.705% as of December 31, 2019)		68
7.500% senior notes due 2031		900
7.875% senior notes due 2031		500
6.450% senior notes due 2036		1,750
Zero Coupon senior notes due 2036		2,271
6.500% note payable to WES due 2038		260
4.300% senior notes due 2039		750
7.950% senior notes due 2039		325
6.200% senior notes due 2040		750
4.500% senior notes due 2044		625
4.625% senior notes due 2045		750
6.600% senior notes due 2046		1,100
4.400% senior notes due 2046		1,200
4.100% senior notes due 2047		750
4.200% senior notes due 2048		1,000
4.400% senior notes due 2049		750
7.730% debentures due 2096		60
7.500% debentures due 2096		78
7.250% debentures due 2096		49
Total borrowings at face value(a)		37,401
Adjustments to book value:
Unamortized premium, net		914
Debt issuance costs		(125		)
Long-term finance leases		347
Long-term Debt, net		$	38,537

^(a)  Total borrowings at face value included a $310 thousand 7.25% senior note due 2025.

OXY 2019 FORM 10-K 83

FINANCIAL STATEMENTS FOOTNOTES

millions	December 31, 2018
Occidental
9.250% senior debentures due 2019		$	116
4.100% senior notes due 2021		1,249
3.125% senior notes due 2022		813
2.600% senior notes due 2022		400
2.700% senior notes due 2023		1,191
8.750% medium-term notes due 2023		22
3.500% senior notes due 2025		750
3.400% senior notes due 2026		1,150
3.000% senior notes due 2027		750
7.200% senior debentures due 2028		82
8.450% senior debentures due 2029		116
4.625% senior notes due 2045		750
4.400% senior notes due 2046		1,200
4.100% senior notes due 2047		750
4.200% senior notes due 2048		1,000
Variable rate bonds due 2030 (1.9% as of December 31, 2018)		68
Total borrowings at face value		10,407
Adjustments to book value:
Unamortized discount, net		(36		)
Debt issuance costs		(54		)
Current maturities		(116		)
Long-term Debt, net		$	10,201

DEBT ISSUED AND ASSUMED

On August 8, 2019, Occidental issued $13.0 billion of new senior unsecured notes, consisting of both floating and fixed rate debt. Occidental also borrowed under the Term Loans, which consist of: (1) a 364-day senior unsecured variable-rate term loan tranche of $4.4 billion and (2) a two-year senior unsecured variable-rate term loan tranche of $4.4 billion. In total, the $21.8 billion in debt issued was used to finance part of the cash portion of the purchase price for the Acquisition.

In the Acquisition, Occidental assumed Anadarko debt with an outstanding principal balance of $11.9 billion. In September 2019, Occidental completed its offers to exchange the Anadarko senior notes and debentures assumed as part of the Acquisition for notes of a corresponding series issued by Occidental and cash, and related solicitation of consents. Of the approximately $11.9 billion in aggregate principal amount of Anadarko senior notes and debentures offered in the exchange, 97%, or approximately $11.5 billion, were tendered and accepted in the exchange offers. The portion not exchanged, approximately $400 million, remains outstanding with the original terms.

DEBT REPAYMENT

In 2019, Occidental paid approximately $7.0 billion of long-term debt including a majority of the Term Loans using proceeds from assets sales and available cash.

REVOLVING CREDIT FACILITY

On June 3, 2019, Occidental entered into an amendment to its existing $3.0 billion revolving credit facility (Occidental RCF) pursuant to which, among other things, the commitments under the Occidental RCF were increased to $5.0 billion at the closing of the Acquisition. Borrowings under the Occidental RCF bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental’s senior debt ratings. The facility has similar terms to other debt agreements and does 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 repayment. The facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. Occidental has not drawn down any amounts under the Occidental RCF. In 2019, Occidental paid average annual facility fees of 0.11% on the total commitment amount.

ZERO COUPON NOTES DUE 2036

The Zero Coupon senior notes due 2036 (Zero Coupons) have an aggregate principal amount due at maturity of approximately $2.3 billion, reflecting an accretion rate of 5.24%. The Zero Coupons can be put to Occidental in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. The Zero Coupons can next be put to Occidental in October 2020, which, if put in whole, would be $992 million at such date. Occidental has the ability and intent to refinance these obligations using long-term debt should a put be exercised.

84 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

DEBT GUARANTEES

As of December 31, 2019, and 2018, Occidental had provided limited recourse guarantees on approximately $242 million and $244 million, respectively, of Dolphin Energy’s debt, which are limited to certain political and other events.

FAIR VALUE OF DEBT

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, 2019, and 2018, substantially all of which were classified as Level 1, were approximately $38.8 billion and $10.3 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, 2019, and 2018, variable-rate debt constituted approximately 12% and 1% of Occidental’s total debt, respectively.

DEBT MATURITIES

At December 31, 2019, future principal payments on long-term debt aggregated approximately $37.4 billion, of which, $6.4 billion is due in 2021, $4.7 billion is due in 2022, $1.2 billion is due in 2023, and $25.1 billion is due in 2024 and thereafter.

NOTE 8 - LEASE COMMITMENTS

On January 1, 2019, Occidental adopted ASC 842 using the modified retrospective approach, which provided a method for recording existing leases at adoption and did not require restatement of prior year amounts and disclosures, which continue to be reflected in accordance with ASC 840. Occidental elected certain practical expedients as follows:

Ø Leases that commenced before the effective date carried forward their historical lease classification.

Ø Existing or expired land easements as of December 31, 2018, were not reassessed to determine whether or not they contained a lease.

Ø Leases with a lease term of 12 months or less from lease commencement date are considered short-term leases and not recorded on the Consolidated Balance Sheet; however, the lease expenditures recognized are captured and reported as incurred.

Ø For asset classes, except long-term drilling rigs, Occidental elected to account for the lease and non-lease components as a single lease component as the non-lease portions were not significant to separate in determining the lease liability. For long-term drilling rig contracts, Occidental bifurcated the lease and non-lease components using relative fair value as a stand-alone selling price between the asset rental and the services obtained.

ASC 842 requires lessees to recognize a ROU asset and lease liability for all long-term leases. A ROU asset represents Occidental’s right to use an underlying asset for the lease term and the associated lease liability represents the discounted obligation of future minimum lease payments. Occidental identifies leases through its accounts payable and contract monitoring process. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. The ROU assets include the discounted obligation in addition to any upfront payments or costs incurred during the contract execution of the lease and amortized on a straight-line basis over the course of the lease term. Except for leases with explicitly defined contract terms, Occidental utilizes judgment to assess likelihood of renewals, terminations and purchase options, in order to determine the lease term. Occidental uses the incremental borrowing rate at commencement date to determine the present value of lease payments. The incremental borrowing rate equates to the rate of interest that Occidental would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. Certain leases include variable lease payments which are over and above the minimum lease liability used to derive the ROU asset and lease liability and are based on the underlying asset’s operations. These variable lease costs are reported in the lease cost classification table.

Recognition, measurement, and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. The criteria for distinguishing between finance and operating leases are substantially similar to the criteria under ASC 840. For Occidental operations, adoption of ASC 842 resulted in recording of net lease assets and lease liabilities of $772 million as of January 1, 2019. There was no material impact to net income, cash flows, or stockholders’ equity.

ACQUISITION IMPACT

ASC 805 Business Combinations requires lease-related assets and liabilities acquired to be measured as if the lease were new at the acquisition date. Occidental measured the Anadarko lease agreements using Occidental’s incremental borrowing rates. This resulted in Anadarko assets and lease liabilities of $503 million and $574 million, respectively, excluding the Africa Assets at the Acquisition date, being evaluated and adjusted, as necessary, for above- or below -market impacts. For the leases acquired through the Acquisition, Occidental will retain the previous lease classification.

OXY 2019 FORM 10-K 85

FINANCIAL STATEMENTS FOOTNOTES

The following table reconciles the undiscounted cash flows related to the operating and finance lease liabilities assumed in the Acquisition and recorded on the Consolidated Balance Sheet at the Acquisition date:

millions	Operating Leases			Finance Leases			Total
2019	$	90		$	7		$	97
2020	172			17			189
2021	64			16			80
2022	42			13			55
2023	28			8			36
Thereafter	136			43			179
Total lease payments	$	532		$	104		$	636
Less: Interest	(44		)	(18		)	(62		)
Total lease liabilities (a)	$	488		$	86		$	574

^(a)  Excluded operating and finance leases associated with the Africa Assets of $74 million and $201 million, respectively.

Additionally, Occidental has elected short-term lease treatment for those acquired lease contracts which, at the Acquisition date, had a remaining lease term of 12 months or less.

NATURE OF LEASES

Occidental’s operating lease agreements include leases for oil and gas exploration and development equipment, including offshore and onshore drilling rigs of $217 million, compressors of $162 million and other field equipment of $389 million, which are recorded gross on the Consolidated Balance Sheet and in the lease cost disclosures below. Contract expiration terms generally range from 2 to 9 years. Further, actual expenditures are netted against joint-interest recoveries on the statement of operations through the normal joint-interest billing process. Occidental’s leases also include pipelines, rail cars, storage facilities, easements and real estate of $659 million, which typically are not associated with joint-interest recoveries. Real estate leases have contract expiration terms ranging from 1 to 14 years.

Occidental’s finance lease agreements include leases for oil and gas exploration and development equipment, as well as real estate offices, compressors, and field equipment of approximately $398 million.

The following table presents lease balances and their location on the Consolidated Balance Sheet at December 31, 2019:

millions	Balance sheet location	2019
Assets:
Operating	Operating lease assets	$	1,385
Finance	Property, plant and equipment	397
Total lease assets		$	1,782
Liabilities:
Current
Operating	Current operating lease liabilities	$	569
Finance	Current maturities of long-term debt	51
Non-current
Operating	Deferred credits and other liabilities - Operating lease liabilities	854
Finance	Long-term debt, net	347
Total lease liabilities		$	1,821

86 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

At December 31, 2019, Occidental’s leases expire based on the following schedule:

millions	Operating Leases(a)			Finance Leases(b)			Total
2020	$	555		$	53		$	608
2021	408			45			453
2022	136			41			177
2023	99			37			136
2024	81			34			115
Thereafter	254			275			529
Total lease payments	1,533			485			2,018
Less: Interest	(110		)	(87		)	(197		)
Total lease liabilities	$	1,423		$	398		$	1,821

^(a)  The weighted-average remaining lease term is 4.6 years and the weighted-average discount rate is 2.53%.

^(b)  The weighted-average remaining lease term is 11.6 years and the weighted-average discount rate is 3.74%.

At December 31, 2018, future undiscounted net minimum fixed lease payments for non-cancellable operating leases, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows:

millions	Operating Leases
2019	$	186
2020	147
2021	96
2022	68
2023	49
Thereafter	158
Total minimum lease payments(a)	$	704

^(a)  The amount represents the future undiscounted cash flows at December 31, 2018, excluding any amount associated with the Acquisition.

The following tables present Occidental’s total lease cost and classifications, as well as cash paid for amounts included in the measurement of operating and finance lease liabilities:

millions	Year ended December 31, 2019
Lease cost classification(a)
Operating lease costs(b)
Property, plant and equipment, net		$	449
Operating expense and cost of sales		391
Selling, general and administrative expenses		92
Finance lease cost
Amortization of ROU assets		19
Interest on lease liabilities		2
Total lease cost		$	953

^(a)  Amounts reflected are gross before joint-interest recoveries.

^(b)  Included short-term lease cost of $404 million for the twelve months ended December 31, 2019, and variable lease cost of $162 million for the twelve months ended December 31, 2019.

millions	Year ended December 31, 2019
Operating cash flows		$	262
Investing cash flows		$	112
Financing cash flows (a)		$	19

^(a)  Excludes cash received of approximately $300 million associated with the failed sale-leaseback, see Note 4 - Acquisitions, Dispositions and Other.

OXY 2019 FORM 10-K 87

FINANCIAL STATEMENTS FOOTNOTES

NOTE 9 - DERIVATIVES

OBJECTIVE AND STRATEGY

Occidental uses a variety of derivative financial instruments and physical contracts to manage its exposure to commodity-price fluctuations, interest rate risks, transportation commitments, and to fix margins on the future sale of stored commodity volumes. Occidental also enters into derivative financial instruments for trading purposes.

Occidental may elect normal purchases and normal sales exclusions when physically delivered commodities are purchased or sold to a customer. Occidental occasionally applies cash flow hedge accounting treatment to derivative financial instruments to lock in margins on the forecasted sales of its natural gas storage volumes, and at times for other strategies, such as to lock rates on forecasted debt issuances. Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. See Note 1 - Summary of Significant Accounting Policies for Occidental’s accounting policy on derivatives.

DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS

As of December 31, 2019, Occidental’s derivatives not designated as hedges consist of three-way oil collars and call options, interest rate swaps, marketing derivatives and the Warrant.

Derivative instruments that are derivatives not designated as hedging instruments are required to be recorded on the balance sheet at fair value. Changes in fair value will impact Occidental’s earnings through mark-to-market adjustments until the physical commodity is delivered or the financial instrument is settled. The fair value does not reflect the realized or cash value of the instrument.

THREE-WAY OIL COLLARS AND CALL OPTIONS

In 2019, Occidental entered into three-way costless collar derivative instruments for 2020 along with additional call options in 2021 to manage its near-term exposure to cash-flow variability from commodity price risks. A three-way collar is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price that Occidental will receive for the contracted commodity volume for a defined period of time. The purchased put establishes the floor price that Occidental will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the floor price equals the reference price plus the difference between the purchased put strike price and the sold put strike price for a defined period of time. Occidental entered into the 2021 call options to substantially improve the terms for the ceiling price that Occidental will receive for the contracted commodity volumes in 2020. Net gains and losses associated with collars and calls are recognized currently in net sales.

Occidental had the following collars and calls outstanding at December 31, 2019:

Collars and Calls, not designated as hedges
2020 Settlement
Three-way collars (oil MMBBL)			128.1
	Volume weighted average price per barrel (Brent oil pricing)
		Ceiling sold price (call)	$	74.16
		Floor purchased price (put)	$	55.00
		Floor sold price (put)	$	45.00
2021 Settlement
Call options sold (oil MMBBL)			127.8
	Volume weighted average price per barrel (Brent oil pricing)
		Ceiling sold price (call)	$	74.16

INTEREST RATE SWAPS

Occidental acquired interest rate swap contracts in the Acquisition. The contracts lock in a fixed interest rate in exchange for a floating interest rate indexed to three-month London Inter-Bank Offered Rate (LIBOR) throughout the reference period. Occidental also acquired interest rate swap contracts held by WES, which were settled as of December 31, 2019. Net gains and losses associated with interest rate derivative instruments not designated as hedging instruments are recognized currently in gains (losses) on interest rate swaps and warrants, net.

88 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

Occidental had the following outstanding interest rate swaps at December 31, 2019:

millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418	%
$	125	September 2016 - 2046	September 2022	6.835	%
$	100	September 2017 - 2047	September 2020	6.891	%
$	250	September 2017 - 2047	September 2021	6.570	%
$	450	September 2017 - 2047	September 2023	6.445	%

Depending on market conditions, liability management actions or other factors, Occidental may enter into offsetting interest rate swap positions or settle or amend certain or all of the currently outstanding interest rate swaps. Occidental settled interest rate swaps with a notional value of $125 million in October 2019. In January and February 2020, Occidental extended September 2020 mandatory termination dates to September 2021 and September 2022 for swaps with a notional value of $500 million and $150 million, respectively.

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. Due to the liability position of the interest rate derivatives at the date of the Acquisition, the interest rate derivatives in Occidental’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization or cash payments related to interest rate derivatives are classified as cash flow from financing activities. Net cash receipts related to settlements, and collateralization of interest rate swap agreements were $120 million during the period from August 8, 2019 through December 31, 2019.

MARKETING DERIVATIVES

Occidental’s marketing derivative instruments not designated as hedges are physical and financial forward contracts which typically settle within three months. A substantial majority of Occidental’s physically settled derivative contracts are index-based and carry no mark-to-market valuation in earnings. These instruments settle at a weighted-average contract price of $60.60 per barrel and $2.17 per thousand cubic feet (Mcf) for oil and natural gas, respectively, at December 31, 2019. The weighted-average contract price was $58.81 per barrel and $3.18 per Mcf for oil and natural gas, respectively, at December 31, 2018. Net gains and losses associated with marketing derivative instruments not designated as hedging instruments are recognized currently in net sales.

The following table summarizes net long/(short) volumes associated with the outstanding marketing commodity derivatives not designated as hedging instruments as of December 31, 2019, and 2018:

	2019		2018
Oil Commodity Contracts
Volume (MMBBL)	55		61
Natural gas commodity contracts
Volume (Bcf)	(128	)	(142	)

THE WARRANT

The Warrant issued with the Preferred Stock in connection with the Acquisition is exercisable at the holder’s option, in whole or in part, until the first anniversary of the date on which no shares of Preferred Stock remain outstanding at which point the Warrant expires. The holder of the Warrant may require net cash settlement if certain shareholder and regulatory approvals to issue Occidental common stock are not obtained on a timely basis. The initial fair value of the Warrant, $188 million, was measured at the date of the Acquisition using the Black Scholes option model. The following inputs were used in the Black Scholes option model: the expected life is based on the estimated term of the Warrant, the volatility factor is based on historical volatilities of Occidental common stock, and the call option price for Occidental common stock at $62.50. The fair value of the Warrant is remeasured each reporting period based on changes in the inputs above.

DERIVATIVES DESIGNATED AS HEDGING INSTRUMENTS

Net gains and losses attributable to derivative instruments subject to cash flow hedge accounting reside in accumulated other comprehensive loss and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings.

OXY 2019 FORM 10-K 89

FINANCIAL STATEMENTS FOOTNOTES

CASH FLOW HEDGES

Occidental’s marketing operations store natural gas purchased from third parties at Occidental’s leased storage facilities. Occidental occasionally elects cash flow hedge accounting for derivative instruments which are used to fix margins on the future sales of the stored volumes. The amount of cash flow hedges related to stored gas, including the ineffective portion, was immaterial for the years ended December 31, 2019, and 2018.

In June 2019, in anticipation of issuing debt in the third quarter to partially finance the cash portion of the Acquisition consideration, Occidental entered into a series of U.S. treasury locks which were designated as cash flow hedges. In August 2019, the U.S. treasury locks were unwound with the issuance of the $13.0 billion new senior unsecured notes, and the resulting after-tax accumulated other comprehensive loss of $125 million will be amortized to interest expense over the life of the underlying senior notes.

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 presents the fair values of Occidental’s outstanding derivatives. Fair values are presented at gross amounts below, including when derivatives are subject to netting arrangements, and are presented on a net basis in the Consolidated Balance Sheets.

millions	Fair Value Measurements Using											Total Fair Value
Balance Sheet Classification	Level 1			Level 2			Level 3		Netting (a)
December 31, 2019
Oil Collars and Calls
Other current assets	$	—		$	92		$	—	$	—		$	92
Deferred credits and other liabilities - other	—			(160		)	—		—			(160		)
Marketing Derivatives
Other current assets	945			79			—		(973		)	51
Long-term receivables and other assets, net	4			12			—		(4		)	12
Accrued liabilities	(1,008		)	(44		)	—		973			(79		)
Deferred credits and other liabilities - other	(4		)	(1		)	—		4			(1		)
Interest Rate Swaps
Other current assets	—			5			—		—			5
Long-term receivables and other assets, net	—			5			—		—			5
Accrued liabilities	—			(657		)	—		—			(657		)
Deferred credits and other liabilities - other	—			(776		)	—		—			(776		)
Warrant
Deferred credits and other liabilities - other	—			(107		)	—		—			(107		)
December 31, 2018
Marketing Derivatives
Other current assets	$	2,531		$	110		$	—	$	(2,392	)	$	249
Long-term receivables and other assets, net	5			9			—		(6		)	8
Accrued liabilities	(2,357		)	(101		)	—		2,392			(66		)
Deferred credits and other liabilities - other	(6		)	(2		)	—		6			(2		)

^(a)  These amounts do not include collateral. As of December 31, 2019, $104 million of collateral has been netted against derivative liabilities related to interest rate swaps. Occidental had $65 million and $54 million of initial margin deposited with brokers as of December 31, 2019 and 2018, respectively, related to marketing derivatives.

90 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

GAINS AND LOSSES ON DERIVATIVES

The following table presents gains and (losses) related to Occidental’s derivative instruments on the Consolidated Statements of Operations:

millions	December 31,
Income Statement Classification	2019			2018		2017
Oil Collars and Calls
Net sales	$	(107	)	$	—	$	—
Marketing Derivatives
Net sales (a)	1,804			2,254		(138		)
Interest Rate Swaps (Excluding WES)
Gain on interest rate swaps and warrants, net	122			—		—
Interest Rate Swaps (WES)
Gain on interest rate swaps and warrants, net	30			—		—
Warrant
Gain on interest rate swaps and warrants, net	81			—		—

^(a)  Included derivative and non-derivative marketing activity.

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 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 party would need to post. The aggregate fair value of derivative instruments with credit-risk-contingent features for which a net liability position existed at December 31, 2019 was $787 million (net of $169 million collateral), primarily related to acquired interest-rate swaps, and $68 million (net of $1 million of collateral) existed at December 31, 2018.

NOTE 10 - ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state, local and international laws and regulations related to improving or maintaining environmental quality. The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and international 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, 2019, Occidental participated in or monitored remedial activities or proceedings at 177 sites, which included 36 sites assumed through the Acquisition. The following table presents Occidental’s current and non-current environmental remediation liabilities as of December 31, 2019 and 2018, the current portion of which is included in accrued liabilities ($162 million in 2019 and $120 million in 2018) and the remainder in deferred credits and other liabilities - environmental remediation liabilities ($1.04 billion in 2019 and $762 million in 2018). Occidental continues to evaluate the remediation obligations assumed through the Acquisition.

Occidental’s environmental remediation sites are grouped into four categories: NPL sites listed or proposed for listing by the EPA on the CERCLA NPL and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

OXY 2019 FORM 10-K 91

FINANCIAL STATEMENTS FOOTNOTES

	2019			2018
millions, except number of sites	Number of Sites	Remediation Balance		Number of Sites	Remediation Balance
NPL sites	36	$	463	34	$	458
Third-party sites	74	311		68	168
Occidental-operated sites	17	154		14	115
Closed or non-operated Occidental sites	50	269		29	141
Total	177	$	1,197	145	$	882

As of December 31, 2019, Occidental’s environmental liabilities exceeded $10 million each at 20 of the 177 sites described above, and 101 of the sites had liabilities from $0 to $1 million each. As of December 31, 2019, 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 — accounted for 94 percent of its liabilities associated with NPL sites. Seventeen of the 36 NPL sites are indemnified by Maxus.

Six of the 74 third-party sites — a Maxus-indemnified chrome site in New Jersey, a former copper mining and smelting operation in Tennessee, a former oil field, a landfill and a chemical plant in California, and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities — accounted for 75 percent of Occidental’s liabilities associated with these sites. Nine of the 74 third-party sites are indemnified by Maxus.

Five sites — oil and gas operations in Colorado and chemical plants in Kansas, Louisiana, New York and Texas — accounted for 67 percent of the liabilities associated with the Occidental-operated sites.

Six other sites — a landfill in Western New York, a former refinery in Oklahoma, former chemical plants in California, Tennessee and Washington, and a closed coal mine in Pennsylvania — accounted for 64 percent of the liabilities associated with closed or non-operated Occidental sites.

Environmental remediation liabilities vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation. Occidental recorded environmental remediation expenses of $112 million, $47 million and $39 million for the years ended December 31, 2019, 2018 and 2017, respectively. Environmental remediation expenses primarily relate to changes to existing conditions from past operations. Based on current estimates, Occidental expects to expend funds corresponding to approximately 40 percent of the year-end remediation balance over the next three to four years with the remainder over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those amounts currently recorded for environmental remediation for all of its environmental sites could be up to $1.1 billion.

MAXUS ENVIRONMENTAL SITES

When Occidental acquired Diamond Shamrock Chemicals Company (DSCC) in 1986, Maxus, 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.

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 remediation liability 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 accrued estimated environmental remediation liability does not consider any recoveries for indemnified costs. Occidental’s ultimate share of the estimated costs may be higher or lower than its accrued remediation liability, and is subject to final design plans and the resolution 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. In June 2018, Occidental filed a complaint under CERCLA in Federal District Court in the State of New Jersey against numerous potentially responsible parties for reimbursement of amounts incurred or to be incurred to comply with the AOC, the ROD or to perform other remediation activities at the Site.

In June 2017, the court overseeing the Maxus bankruptcy approved a Plan of Liquidation (Plan) to liquidate Maxus and create a trust to pursue claims against YPF, Repsol and others to satisfy claims by Occidental and other creditors for past and future cleanup and other costs. In July 2017, the court-approved Plan became final and the trust became effective. Among other responsibilities, the trust will pursue claims against YPF, Repsol and others and distribute assets to Maxus’ creditors in accordance with the trust agreement and Plan. In June 2018, the trust filed its complaint against YPF and Repsol in Delaware bankruptcy court asserting claims based upon, among other things, fraudulent transfer and alter ego. On February 15, 2019, the bankruptcy court denied Repsol’s and YPF’s motions to dismiss the complaint.

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NOTE 11 - LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

LEGAL MATTERS

Occidental 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. Occidental or certain of its subsidiaries also are involved in proceedings under 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 Occidental 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 outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserves for matters, other than for environmental remediation, that satisfy this criteria as of December 31, 2019, and December 31, 2018, were not material to Occidental’s Consolidated Balance Sheets.

On May 30, 2019, a complaint was filed in the Court of Chancery of the State of Delaware by purported Occidental stockholders High River Limited Partnership, Icahn Partners Master Fund LP and Icahn Partners LP (the “Icahn Complainants”), captioned High River Ltd. P’ship v. Occidental Petroleum Corp., C.A. No. 2019-0403-JRS, seeking inspection of Occidental’s books and records pursuant to Section 220 of the Delaware General Corporation Law. In the complaint, the Icahn Complainants noted that they had accumulated over $1.6 billion of Occidental Common Stock. On June 14, 2019, Occidental filed an answer to the complaint in the Court of Chancery of the State of Delaware. A trial was held on September 20, 2019, and the court dismissed the Icahn Complaint. The Icahn Complainants appealed and oral arguments occurred in February 2020.

In 2016, Occidental received payments from the Republic of Ecuador of approximately $1.0 billion pursuant to a November 2015 arbitration award for Ecuador’s 2006 expropriation of Occidental’s Participation Contract for Block 15. The awarded amount represented a recovery of 60 percent of the value of Block 15. In 2017, Andes Petroleum Ecuador Ltd. (Andes) filed a demand for arbitration, claiming it is entitled to a 40 percent share of the judgment amount obtained by Occidental. Occidental contends that Andes is not entitled to any of the amounts paid under the 2015 arbitration award because Occidental’s recovery was limited to Occidental’s own 60 percent economic interest in the block. The merits hearing is scheduled for May 2020. Occidental intends to vigorously defend against this claim in arbitration.

The ultimate outcome and impact of outstanding lawsuits, claims and proceedings on Occidental cannot be predicted. Management believes that the resolution of these matters will not, individually or in the aggregate, have a material adverse effect on Occidental’s Consolidated Balance Sheets. If unfavorable outcomes of these matters were to occur, future results of operations or cash flows for any particular quarterly or annual period could be materially adversely affected. Occidental’s estimates are based on information known about the legal matters and its experience in contesting, litigating and settling similar matters. 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. Taxable years through 2016 for U.S. federal income tax purposes have been audited by the U.S. Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program and subsequent taxable years are currently under review. Taxable years through 2009 have been audited for state income tax purposes. While a single foreign tax jurisdiction is open for 2002, all other significant audit matters in foreign jurisdictions have been resolved through 2010. 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.

For Anadarko, its taxable years through 2016 for U.S. federal and state income tax purposes have been audited by the IRS and respective state taxing authorities. There are outstanding significant audit matters in one foreign jurisdiction. During the course of the tax audit, disputes have arisen and other disputes may arise as to facts and matters of law. Other than the matter discussed below, Occidental believes that the resolution of these outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.

Anadarko received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. In September 2018, Anadarko received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting Anadarko’s refund claim. As a result, Anadarko filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018. The case is currently in the IRS appeals process. If the matter is not resolved in the IRS appeals process, Occidental expects to continue pursuing resolution in the U.S. Tax Court.

While Occidental believes it is entitled to this refund, in accordance with ASC 740’s guidance on the accounting for uncertain tax positions, as of December 31, 2019, Occidental has recorded no tax benefit on the tentative cash tax refund of

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$881 million. As a result, should Occidental not ultimately prevail on the issue, there would be no additional tax expense recorded for financial statement purposes other than future interest. However, in that event Occidental would be required to repay approximately $925 million ($898 million federal and $27 million in state taxes) plus accrued interest of approximately $189 million. As a result, a liability for this amount has been recorded in deferred credits and other liabilities - other at December 31, 2019.

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, 2019, 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.

PURCHASE OBLIGATIONS AND COMMITMENTS

Occidental, 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, 2019, total purchase obligations were $20.7 billion, which included approximately $3.3 billion in 2020, $5.7 billion in 2021 and 2022, $4.7 billion in 2023 and 2024, and $7.1 billion in 2025 and thereafter.

NOTE 12 - INCOME TAXES

The following summarizes domestic and foreign components of income (loss) from continuing operations before domestic and foreign income taxes for the years ended December 31:

millions	2019			2018		2017
Domestic	$	(1,632	)	$	3,431	$	(609	)
Foreign	1,818			2,177		1,937
Total	$	186		$	5,608	$	1,328

The following summarizes components of income tax expense (benefit) on continuing operations for the years ended December 31:

millions	2019			2018			2017
Current
Federal	$	33		$	(23	)	$	(81	)
State and Local	46			52			11
Foreign	1,641			1,077			806
Total current tax expense	$	1,720		$	1,106		$	736
Deferred
Federal	(130		)	422			(856		)
State and Local	17			12			23
Foreign	(914		)	(63		)	114
Total deferred tax expense (benefit)	$	(1,027	)	$	371		$	(719	)
Total income tax expense	$	693		$	1,477		$	17

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The following reconciliation of the U.S federal statutory income tax rate to Occidental’s worldwide effective tax rate on income from continuing operations for the years ended December 31 is stated as a percentage of income (loss) from continuing operations before income taxes:

	2019		2018		2017
U.S. federal statutory tax rate	21	%	21	%	35	%
Enhanced oil recovery credit and other general business credits	(4	)	(3	)	(9	)
Change in federal income tax rate	—		—		(44	)
Tax (benefit) expense due to reversal of indefinite reinvestment assertion	—		(2	)	7
Tax impact from foreign operations	187		11		12
State income taxes, net of federal benefit	28		1		2
Uncertain tax positions	13		—		—
Transaction costs	19		—		—
Non-controlling interest	(16	)	—		—
Executive compensation limitation	24		—		—
Stock warrants	(9	)	—		—
WES loss of control	113		—		—
Other	(3	)	(2	)	(2	)
Worldwide effective tax rate	373	%	26	%	1	%

In 2019, Occidental’s worldwide effective tax rate was 373%, which was largely a result of Acquisition-related costs and charges associated with the loss of control of WES for which Occidental received no tax benefit.

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2019, and 2018 were as follows:

millions	2019			2018
Deferred tax liabilities
Property, plant and equipment differences	$	(12,375	)	$	(2,089	)
Equity investments, partnerships and foreign subsidiaries	(989		)	(161		)
Gross long-term deferred tax liabilities	(13,364		)	(2,250		)
Deferred tax assets
Environmental reserves	261			195
Postretirement benefit accruals	441			176
Deferred compensation and benefits	266			170
Asset retirement obligations	906			280
Foreign tax credit carryforwards	4,379			2,356
General business credit carryforwards	443			429
Net operating loss carryforward	692			29
Interest expense carryforward	492			—
All other	782			111
Gross long-term deferred tax assets	8,662			3,746
Valuation allowance	(4,959		)	(2,403		)
Net long-term deferred tax assets	$	3,703		$	1,343
Less: Foreign deferred tax asset in long-term receivables and other assets, net	$	(56	)	$	—
Total deferred income taxes, net	$	(9,717	)	$	(907	)

Total deferred tax assets, after valuation allowances, were $3.7 billion and $1.3 billion as of December 31, 2019, and 2018, respectively. Occidental expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The total deferred tax liabilities were $13.4 billion and $2.3 billion as

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of December 31, 2019 and 2018, respectively. The increase in net deferred tax liability in 2019 over 2018 is primarily due to the acquisition of Anadarko offset by the generation of interest expense and operating loss carryforwards in 2019.

As of December 31, 2019, Occidental had foreign tax credit carryforwards of $4.4 billion, federal general business credits carryforwards of $404 million, tax-effected foreign net operating loss carryforwards of $209 million, tax-effected state operating loss carryforwards of $292 million and state tax credit carryforwards of $39 million. These carryforward balances have varying carryforward periods through 2039. Occidental has recorded a valuation allowance for all of the foreign tax credit carryforwards, $240 million of the tax-effected state net operating loss carryforwards $32 million of the state tax credit carryforwards and all of the tax-effected foreign net operating loss carryforwards.

A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated international subsidiaries aggregating approximately $889 million at December 31, 2019, as it is Occidental’s intention to reinvest such earnings indefinitely. If the earnings of these international subsidiaries were not indefinitely reinvested, an additional deferred tax liability of approximately $206 million would be required.

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

millions	2019		2018			2017
Balance at January 1	$	—	$	22		$	22
Increase related to Anadarko Acquisition	2,143		—			—
Increases related to current-year positions	30		—			—
Settlements	—		(22		)	—
Balance at December 31	$	2,173	$	—		$	22

The December 31, 2019 balance of unrecognized tax benefits of $2.2 billion included potential benefits of $2.0 billion of which, if recognized, $1.7 billion would affect the effective tax rate on income. Also included are benefits of $131 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain. Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes. The Company accrued approximately $199 million of interest related to liabilities for unrecognized tax benefits as of December 31, 2019. During 2019, Occidental recorded interest related to liabilities for unrecognized tax benefits of $30 million. There were no interest and penalties associated with liabilities for unrecognized tax benefits recorded for the years ended December 31, 2018 and 2017. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $100 million to $110 million due to settlements with taxing authorities or lapse in statutes of limitation.

Occidental has recognized $86 million and $68 million in federal and state income tax receivables at December 31, 2019, and 2018, respectively, which was recorded in other current assets. In addition, Occidental has recognized $36 million and $68 million in federal alternative minimum tax non-current receivables at December 31, 2019, and 2018, respectively, which was recorded in long-term receivables and other assets, net.

Occidental is subject to audit by various tax authorities in varying periods. See Note 11 - Lawsuits, Claims, Commitments and Contingencies for a discussion of these matters.

NOTE 13 - STOCKHOLDERS’ EQUITY

The following is a summary of common stock issuances:

Shares in thousands	Common Stock
Balance, December 31, 2016	892,215
Issued	1,252
Options exercised and other, net	2
Balance, December 31, 2017	893,469
Issued	1,628
Options exercised and other, net	19
Balance, December 31, 2018	895,116
Issued in the ordinary course	3,188
Issued as part of the Acquisition (a)	146,131
Balance, December 31, 2019	1,044,435

^(a)  Included approximately 2 million shares of common stock issued to a benefits trust for former Anadarko employees treated as treasury stock at December 31, 2019.

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TREASURY STOCK

The total number of shares authorized for Occidental’s share repurchase program is 185 million shares of which 44.2 million may yet be purchased under the repurchase program. However, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time. In 2019, 2.7 million shares were purchased at an average price of $66.94 under the program and in 2018, 16.9 million shares were purchased at an average price of $74.92. No shares were purchased under the program in 2017. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year. As of December 31, 2019, 2018 and 2017, treasury stock shares numbered 150.3 million, 145.7 million, and 128.4 million, respectively.

PREFERRED STOCK

Occidental has authorized 50 million shares of preferred stock with a par value of $1.00 per share. On August 8, 2019, in connection with the Acquisition, Occidental issued 100,000 shares of series A preferred stock (the Preferred Stock), having a face value of $100,000 per share and a liquidation preference of $105,000 per share plus unpaid accrued dividends. In connection with the preferred stock issuance, Occidental also issued the Warrant. The holder of the Warrant and the Preferred Stock may redeem the Preferred Stock as payment for the exercise price of the Warrant in lieu of cash payment upon exercise. The Preferred Stock is redeemable at Occidental’s option after the 10th anniversary of issuance. Dividends on the Preferred Stock will accrue on the face value at a rate per annum of 8 percent, but will be paid only when, as, and if declared by Occidental’s Board of Directors. At any time, when such dividends have not been paid in full, the unpaid amounts will accrue dividends, compounded quarterly, at a rate per annum of 9 percent. Following the payment in full of any accrued but unpaid dividends, the dividend rate will remain at 9 percent per annum. In January 2020, Occidental paid $200 million in Preferred Stock dividends. At December 31, 2019, Occidental had 100,000 shares of preferred stock issued and outstanding, and none were outstanding in 2018 and 2017.

EARNINGS PER SHARE

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

millions except per share amounts	2019			2018			2017
Income (loss) from continuing operations	$	(507	)	$	4,131		$	1,311
Loss from discontinued operations	(15		)	—			—
Net income (loss)	$	(522	)	$	4,131		$	1,311
Less: Net income attributable to noncontrolling interest	(145		)	—			—
Less: Preferred stock dividends	(318		)	—			—
Net income (loss) attributable to common stock	$	(985	)	$	4,131		$	1,311
Less: Net income allocated to participating securities	—			(17		)	(6		)
Net income (loss), net of participating securities	$	(985	)	$	4,114		$	1,305
Weighted-average number of basic shares	809.5			761.7			765.1
Basic earnings (loss) per common share	$	(1.22	)	$	5.40		$	1.71
Net income (loss), net of participating securities	$	(985	)	$	4,114		$	1,305
Weighted-average number of basic shares	809.5			761.7			765.1
Dilutive securities	—			1.6			0.8
Total diluted weighted-average common shares	809.5			763.3			765.9
Diluted earnings (loss) per common share	$	(1.22	)	$	5.39		$	1.70

ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss consisted of the following after-tax amounts at December 31:

millions	2019			2018
Foreign currency translation adjustments	$	(7	)	$	(7	)
Unrealized gains (losses) on derivatives	(122		)	5
Pension and postretirement adjustments (a)	(92		)	(170		)
Total	$	(221	)	$	(172	)

^(a)  See Note 15 - Retirement and Postretirement Benefit Plans for further information.

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NOTE 14 - STOCK-BASED INCENTIVE PLANS

Occidental issues stock-based awards to employees in accordance with the terms of the shareholder approved 2015 Long-Term Incentive Plan (2015 LTIP). An aggregate of 80 million shares of Occidental common stock were authorized for issuance and approximately 6.6 million shares had been allocated to employee awards through December 31, 2019. As of December 31, 2019, approximately 52.5 million shares were available for grants of future awards. The plan requires each share covered by an award (other than 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 52.5 million depending on the type of award granted, and shares available for future awards may increase by the number of shares that are forfeited, canceled, or correspond to the portion of any stock-based awards settled in cash, including awards that were issued under a previous plan that remain outstanding. Current outstanding awards include RSUs, stock options, CROCEIs, and TSRIs.

During 2019, non-employee directors were granted awards for 41,752 shares of 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.

For the year ended December 31, 2019, Occidental incurred expenses of $208 million related to stock-based incentive plans, of which $31 million was related to the Acquisition. For the years ended December 31, 2018, and 2017, expense related to stock-based incentive plans was $180 million, and $150 million, respectively. The income tax benefit associated with this expense was $43 million, $47 million, and $32 million in the years ended December 31, 2019, 2018, and 2017, respectively.

As of December 31, 2019, unrecognized compensation expense for all unvested stock-based incentive awards was $354.1 million. This expense is expected to be recognized over a weighted-average period of 1.9 years. Occidental accounts for forfeitures as they occur.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs may be settled in stock or may be cash settled liabilities. These awards vest from one to 4 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 RSUs, dividend equivalents are paid during the vesting period.

CASH-SETTLED LIABILITY AWARDS

The weighted-average, grant-date fair values of cash-settled RSUs granted in 2019, 2018 and 2017 were $42.62, $75.86, and $66.62 per share, respectively. Cash-Settled RSUs resulted in payments of $4 million, $18 million, and $23 million, during the years ended December 31, 2019, 2018 and 2017, respectively.

STOCK-SETTLED EQUITY AWARDS

The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2019, 2018, and 2017 were $58.73, $69.87, and $67.21, respectively. The fair value of RSUs settled in shares during the years ended December 31, 2019, 2018 and 2017 was $148 million, $109 million, and $64 million, respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2019, is presented below:

	Cash-Settled					Stock-Settled
thousands, except fair values	RSUs		Weighted-Average Grant-Date Fair Value			RSUs		Weighted-Average Grant-Date Fair Value
Unvested at January 1	186			$	73.93	3,971			$	73.19
Granted (a)	4,267			$	42.62	3,543			$	58.73
Vested	(67	)		$	72.26	(2,743	)		$	67.04
Forfeitures	(39	)		$	47.60	(376	)		$	67.25
Unvested at December 31	4,347			$	43.46	4,395			$	65.88

^(a)  Included 1.5 million shares issued in exchange for Anadarko stock-based incentive shares.

TSRIs

Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date. Payout is based upon Occidental’s absolute total shareholder return and performance relative to its peers. TSRIs have payouts that range from 0% to 200% of the target award and settle in stock once certified. Dividend equivalents for TSRIs are accumulated and paid upon certification of the award. The fair value of TSRIs settled in shares during the years ended December 31, 2019, 2018 and 2017 was $4 million, $12 million, and $5 million, respectively.

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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 (U.S. 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
	2019			2018			2017
Assumptions used:
Risk-free interest rate	2.5		%	2.3		%	1.5		%
Volatility factor	22		%	24		%	25		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	67.19		$	69.87		$	67.21

A summary of Occidental’s unvested TSRIs as of December 31, 2019 and changes during the year ended December 31, 2019 is presented below:

	TSRIs
thousands, except fair values	Awards		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	1,444			$	70.97
Granted	578			$	67.19
Vested (a)	(442	)		$	76.83
Forfeitures	(43	)		$	76.83
Unvested at December 31	1,537			$	67.70

^(a)  Presented at the target payouts. The weighted-average payout at vesting was 19% of the target, resulting in the issuance of approximately 83,000 shares of Occidental common stock.

STOCK OPTIONS

Certain employees have been granted options that are settled in stock. Exercise prices of the options were equal to the quoted market value of Occidental’s stock on the grant date. No options were granted, vested or forfeited in 2019. The intrinsic value of options exercised during the years ended December 31, 2019, 2018, and 2017 was insignificant. As of December 31, 2019, there were 530,000 fully vested options outstanding with an exercise price of $79.98 per share and a remaining life of 2.1 years.

CROCEI, ROCEI and ROAI

Certain executives are awarded CROCEI, ROCEI or ROAI awards that vest at the end of a three-year period if performance targets based on cash return on capital employed, return on capital employed, or return on assets are certified as being met. These awards are settled in stock upon certification of the performance target, with payouts that range from 0% to 200% of the target award. Dividend equivalents are accumulated and paid upon certification of the award.

	CROCEI, ROCEI, and ROAI
thousands, except fair values	Awards		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	210			$	71.60
Granted	81			$	67.19
Vested (a)	(137	)		$	72.54
Forfeited	—			—
Unvested at December 31	154			$	68.44

^(a)  Presented at the target payouts. The weighted-average payout at vesting was 86% of the target resulting in the issuance of approximately 118,000 shares.

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NOTE 15 - RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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

In conjunction with the Acquisition, Occidental acquired certain Anadarko contributory and non-contributory defined benefit pension plans, which include both qualified and supplemental plans, and plans that provide health care and life insurance benefits for certain retired employees. The Anadarko pension and postretirement obligations were remeasured as of the Acquisition date. The remeasurement resulted in an increase to the benefit obligation of $193 million. The disclosures below exclude the plans related to the Africa Assets classified as held for sale as of December 31, 2019.

During the third quarter of 2018, Occidental adopted a postretirement benefit plan design change, which replaced the previous self-insured benefit with a Medicare Advantage PPA plan for Medicare-eligible retirees. As a result of this change, the postretirement benefit obligation was remeasured as of August 31, 2018. The remeasurement resulted in a decrease to the benefit obligation of $178 million with a corresponding offset to accumulated other comprehensive income.

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, 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 $279 million and $201 million as of December 31, 2019, and 2018, respectively, and Occidental expensed $211 million in 2019, $152 million in 2018 and $130 million in 2017 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited. Approximately 4,000 domestic and 600 foreign national employees, mainly union, nonunion hourly and certain employees that joined Occidental from acquired operations with grandfathered benefits, are currently accruing benefits under these plans.

Pension costs for Occidental’s defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.

POSTRETIREMENT AND OTHER BENEFIT PLANS

Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. Occidental generally funds the benefits as they are paid during the year. These benefit costs, including the postretirement costs, were approximately $220 million in 2019, $182 million in 2018 and $181 million in 2017.

OBLIGATIONS AND FUNDED STATUS

The following tables show the amounts recognized in Occidental’s consolidated balance sheets at December 31, 2019 and 2018, related to its pension and postretirement benefit plans:

	Pension Benefits						Postretirement Benefits
millions	2019			2018			2019			2018
Amounts recognized in the consolidated balance sheet:
Long-term receivables and other assets, net	$	85		$	60		$	—		$	—
Accrued liabilities	(96		)	(25		)	(72		)	(45		)
Deferred credits and other liabilities — pension and postretirement obligations	(704		)	(46		)	(1,103		)	(763		)
	$	(715	)	$	(11	)	$	(1,175	)	$	(808	)
Accumulated other comprehensive loss included the following after-tax balances:
Net (gain) loss	$	(25	)	$	91		$	184		$	151
Prior service credit	—			—			(67		)	(72		)
	$	(25	)	$	91		$	117		$	79

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FINANCIAL STATEMENTS FOOTNOTES

The following tables show the funding status, obligations and plan asset fair values of Occidental related to its pension and postretirement benefit plans for the years ended December 31:

	Pension Benefits						Postretirement Benefits
millions	2019			2018			2019			2018
Changes in the benefit obligation:
Benefit obligation — beginning of year	$	349		$	391		$	808		$	999
Service cost — benefits earned during the period	45			5			24			23
Interest cost on projected benefit obligation	39			15			36			34
Actuarial (gain) loss	(33		)	(19		)	45			(90		)
Foreign currency exchange rate gain	—			(3		)	—			—
Curtailment (gain) loss	(136		)	—			10			—
Special termination benefits	49			—			—			—
Benefits paid	(95		)	(40		)	(51		)	(57		)
Participant contributions	—			—			2			—
Plan amendments	—			—			—			(101		)
Additions due to the Acquisition	2,136			—			301			—
Benefit obligation — end of year	$	2,354		$	349		$	1,175		$	808
Changes in plan assets:
Fair value of plan assets — beginning of year	$	338		$	403		$	—		$	—
Actual return on plan assets	122			(33		)	—			—
Participant contributions	—			—			2			—
Employer contributions	41			8			49			—
Benefits paid	(95		)	(40		)	(51		)	—
Additions due to the Acquisition	1,233			—			—			—
Fair value of plan assets — end of year	$	1,639		$	338		$	—		$	—
Unfunded status:	$	(715	)	$	(11	)	$	(1,175	)	$	(808	)

The following table sets forth details of the obligations and assets of Occidental’s defined benefit pension plans for the years December 31:

	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
millions	2019		2018		2019		2018
Projected benefit obligation	$	2,175	$	173	$	179	$	176
Accumulated benefit obligation	$	1,918	$	169	$	179	$	176
Fair value of plan assets	$	1,375	$	98	$	264	$	240

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FINANCIAL STATEMENTS FOOTNOTES

COMPONENTS OF NET PERIODIC BENEFIT COST

The following table sets forth the components of net periodic benefit costs for the years ended December 31:

	Pension Benefits									Postretirement Benefits
millions	2019			2018			2017			2019			2018			2017
Net periodic benefit costs:
Service cost — benefits earned during the period	$	45		$	5		$	6		$	24		$	23		$	21
Interest cost on projected benefit obligation	39			15			17			36			34			38
Expected return on plan assets	(50		)	(25		)	(24		)	—			—			—
Recognized actuarial loss	9			7			10			8			14			14
Recognized prior service credit	—			—			—			(8		)	—			—
Liability (gain) loss due to curtailment	(91		)	—			—			6			—			—
Special termination benefits	49			—			—			—			—			—
Other costs and adjustments	(2		)	1			3			—			(2		)	1
Net periodic benefit cost	$	(1	)	$	3		$	12		$	66		$	69		$	74

The service cost component of net periodic benefit cost is included in selling, general and administrative, oil and gas operating expense, chemical and midstream costs, and exploration expense on Occidental’s Consolidated Statements of Operations. All other components of net periodic benefit cost are included in other operating and non-operating expense.

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from Accumulated Other Comprehensive Income (AOCI) into net periodic benefit cost over the next fiscal year are $3 million and zero, respectively. The estimated net loss and prior service credit for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $12 million and $(8) 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 for the years ended December 31:

	Pension Benefits				Postretirement Benefits
	2019		2018		2019		2018
Benefit Obligation Assumptions:
Discount rate	3.10	%	4.09	%	3.26	%	4.29	%
Net Periodic Benefit Cost Assumptions:
Discount rate for January 1 - August 31 expense	3.21	%	3.45	%	3.41	%	3.61	%
Discount rate for September 1 - December 31 expense	3.21	%	3.45	%	3.41	%	4.14	%
Assumed long-term rate of return on assets	6.50	%	6.50	%	—		—
Rates of increase in compensation levels	5.44	%	—		—		—

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on AA-AAA Universe yield curve in 2019 and 2018. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end. Assumed rates of compensation increases for active participants in certain plans and vary by age group.

In 2019, Occidental adopted the Society of Actuaries 2019 Pri-2012 Private Retirement Plans Mortality Tables with Mortality Improvement Scale, which updated the mortality assumptions that private defined-benefit plans in the United States use in the actuarial valuations that determine a plan sponsor’s pension obligations. The new mortality assumption reflects additional data that the Social Security Administration has released since the previous mortality tables and improvement scales were released. This additional data shows a lower degree of mortality improvement than previously reflected. The changes in the mortality assumption results in a decrease of $15 million and $9 million in the pension and postretirement benefit obligation, respectively, at December 31, 2019.

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% to 8.8% at December 31, 2019 and from 1.0% to 8.9% at December 31, 2018. The average rate of increase in future compensation levels ranged from 1.0% to 8.0% in 2019, depending on local economic conditions.

The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial

102 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

assumptions and health care cost trend rates. Health care cost trend rates for Medicare advantaged prescription drug (MAPD) plans of 4.3% to 21.5% in 2019, between (7.7)% and (6.2)% in 2020, 9.6% in 2021, then grading down to 4.5% in 2028 and beyond. The negative trend rates for the MAPD plans reflect the repeal of the Health Insurer Fee effective in 2021. Health care cost trend rates used for non-MAPD plans are 6.7% to 7.5% in 2019, then grading down to 4.5% in 2028 and beyond.

A 1% increase or a 1% decrease in these assumed health care cost trend rates would result in an increase of $131 million or a reduction of $103 million, respectively, in the postretirement benefit obligation and increase of $13 million or a reduction of $9 million in the annual service and interest costs as of December 31, 2019.

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

FAIR VALUE OF PENSION PLAN ASSETS

Pension plan assets are monitored by Occidental’s Pension and Retirement Trust and Investment Committee or by the Investment Subcommittee of the Anadarko Petroleum Corporation Administrative & Investment Committee (collectively, the Investment Committees), in their roles as fiduciaries. The Investment Committees select and employ various external professional investment management firms to manage specific investments across the spectrum of asset classes. The Investment Committees employ a total return investment approach that uses a diversified blend of investments across several categories (equity securities, fixed-income securities, real estate, hedge funds, and private equity) to optimize the long-term return of plan assets at a prudent level of risk. Equity investments are diversified across U.S. and non-U.S. stocks, as well as differing styles and market capitalizations. 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 were as follows:

millions	Level 1		Level 2		Level 3		Total
December 31, 2019
Asset Class:
U.S. government securities	$	13	$	—	$	—	$	13
Corporate bonds (a)	—		60		—		60
Mutual funds:
Bond funds	46		—		—		46
International funds	68		—		—		68
Common and preferred stocks (b)	173		—		—		173
Other	—		29		—		29
Investments measured at fair value	$	300	$	89	$	—	$	389
Investments measured at net asset value (c)	—		—		—		1,253
Total pension plan assets (d)	$	300	$	89	$	—	$	1,642
December 31, 2018
Asset Class:
U.S. government securities	$	17	$	—	$	—	$	17
Corporate bonds (a)	—		66		—		66
Common/collective trusts (e)	—		9		—		9
Mutual funds:
Bond funds	31		—		—		31
Blend funds	48		—		—		48
Common and preferred stocks (b)	141		—		—		141
Other	—		31		—		31
Total pension plan assets (d)	$	237	$	106	$	—	$	343

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

^(b)  This category included 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)  Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.

^(e)  Amounts exclude net payables of approximately $3 million and $5 million as of December 31, 2019 and 2018, respectively.

OXY 2019 FORM 10-K 103

FINANCIAL STATEMENTS FOOTNOTES

Occidental expects to contribute $179 million in cash to its defined benefit pension plans during 2020. Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows for the years ended December 31:

millions	Pension Benefits		Postretirement Benefits
2020	$	810		$	73
2021	$	113		$	72
2022	$	125		$	71
2023	$	128		$	70
2024	$	124		$	68
2025 - 2029	$	625		$	321

NOTE 16 - INVESTMENTS AND RELATED-PARTY TRANSACTIONS

EQUITY INVESTMENTS

As of December 31, 2019, and 2018, investments in unconsolidated entities were $6.4 billion and $1.7 billion, respectively. As of December 31, 2019, Occidental’s significant equity investments primarily consisted of the following:

millions	% Interest		Carrying amount
WES	56.3	%	$	5,128
OxyChem Ingleside Facility	50.0	%	679
Dolphin Energy Limited	24.5	%	240
Other	various		342
Total			$	6,389

As of December 31, 2018, Occidental’s significant equity investments consisted of investments in Plains, OxyChem Ingleside Facility and Dolphin Energy Limited. In September 2019, Occidental sold its equity investment in Plains, which consisted of an 11 percent interest in the general partner that owned approximately 40 percent in Plains Pipeline. See Note 4 - Acquisitions, Dispositions, and Other Transactions for additional information.

As part of the Acquisition, Occidental acquired equity investments in certain oil and gas properties and gathering and processing assets and assumed an associated notes payable which Occidental has the legal right of setoff and intends to net settle with its ownership interest in the equity investments. The notes payable can be net settled starting in 2022. The carrying value of the investment and note payable was $2.8 billion and $2.8 billion at December 31, 2019, respectively. Accordingly, the equity investments and the related notes payable are presented net on the Consolidated Balance Sheets. 

Dividends received from equity investments were $422 million, $329 million, and $297 million to Occidental in 2019, 2018 and 2017, respectively. As of December 31, 2019, cumulative undistributed earnings of equity-method investees since they were acquired was immaterial. As of December 31, 2019, Occidental’s investments in equity investees exceeded the underlying equity in net assets by approximately $3.6 billion, of which $1.5 billion represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

The following table presents the summarized financial information of its equity-method investments combined for the years ended and as of December 31:

millions	2019		2018		2017
Summarized Results of Operations(a)
Revenues and other income	$	26,520	$	28,091	$	13,843
Costs and expenses	24,084		25,029		12,230
Net income	$	2,436	$	3,062	$	1,613
Summarized Balance Sheet(b)
Current assets	$	1,130	$	5,587	$	5,754
Non-current assets	$	21,158	$	25,871	$	25,108
Current liabilities	$	785	$	4,879	$	4,479
Long-term debt	$	8,673	$	12,505	$	14,091
Other non-current liabilities	$	859	$	95	$	414
Stockholders’ equity	$	11,971	$	13,979	$	11,878

^(a)  The 2019 Summarized Results of Operations include results of Plains for the period beginning January 1, 2019 through the date Occidental’s interest was sold in September 2019.

^(b)  The 2019 Summarized Balance Sheet included the balance of WES due to the loss of control on December 30, 2019 and excluded the balances of Plains as the interest was sold in September 2019.

RELATED-PARTY TRANSACTIONS

From time to time, Occidental purchases oil, NGL, power, steam and chemicals from and sells oil, NGL, natural gas, chemicals and power to certain of its equity investees and other related parties. During 2019, 2018 and 2017, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties for the years ended December 31:

millions	2019		2018		2017
Sales (a,c)	$	691	$	805	$	636
Purchases (b,c)	$	463	$	502	$	387
Services	$	28	$	52	$	38
Advances and amounts due from related parties	$	133	$	63	$	63
Amounts due to related parties (d)	$	463	$	46	$	45

^(a)  In 2019, 2018 and 2017, sales of Occidental-produced oil and NGL to Plains Pipeline affiliates accounted for 87 percent, 89 percent and 86 percent of these totals, respectively. In September 2019, Occidental sold its remaining interest in Plains Pipeline.

^(b)  In 2019 and 2018, purchases of ethylene from the Ingleside ethylene cracker accounted for 98 percent of related-party purchases, respectively.

^(c)  Excluded sales to and purchases from WES as it was a consolidated subsidiary from the date of the Acquisition through December 31, 2019.

^(d)  Amounts due to related parties at December 31, 2019 primarily consists of a 6.5% note payable to WES due 2038.

NOTE 17 - FAIR 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 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.

104 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis:

millions	Fair Value Measurements Using								Total Fair Value
Balance Sheet Classification	Level 1		Level 2		Level 3		Netting
December 31, 2019
Embedded Derivatives
Accrued liabilities	$	—	$	40	$	—	$	—	$	40
Deferred credits and other liabilities - other	$	—	$	49	$	—	$	—	$	49
December 31, 2018
Embedded Derivatives
Accrued liabilities	$	—	$	66	$	—	$	—	$	66
Deferred credits and other liabilities - other	$	—	$	116	$	—	$	—	$	116

FAIR VALUES – NONRECURRING

During 2019, Occidental measured assets and liabilities at acquisition-date fair value on a nonrecurring basis related to the Acquisition. See Note 3 - The Acquisition for more detail.

In 2019, Occidental recorded a $1 billion charge as a result of recording Occidental’s equity investment in WES at fair value upon loss of control, see Note 1 - Summary of Significant Accounting Policies. Additionally, Occidental’s oil and gas segment recognized pre-tax impairment and related charges of $285 million related to domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and $39 million related to Occidental’s mutually agreed early termination of its Qatar ISSD contract.

During 2018, Occidental recognized pre-tax impairment and related charges of $416 million primarily related to Qatar ISND and ISSD proved properties and inventory. The fair value of the proved properties was measured based on the income approach, which 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, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk-adjusted discount rate of 10 percent. These inputs are categorized as Level 3 in the fair value hierarchy.

During 2017, Occidental recognized pre-tax impairment charges of $397 million primarily related to held for sale non-core proved and unproved Permian acreage. Assumptions for proved and unproved properties classified as held for sale include estimated third-party prices to be received based on recent transactions of similar acreage.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash, cash equivalents, restricted cash and restricted cash equivalents and other on-balance sheet financial instruments, other than fixed-rate debt, approximate fair value. See Note 7 - Long-term Debt for the fair value of Long-term debt.

NOTE 18 - INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental conducts its operations through three segments: (1) oil and gas; (2) chemical; and (3) marketing and midstream.

Income taxes, interest income, interest expense, environmental remediation expenses, Anadarko acquisition-related costs and unallocated corporate expenses are included under Corporate and Eliminations. 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.

OXY 2019 FORM 10-K 105

FINANCIAL STATEMENTS FOOTNOTES

millions	Oil and Gas			Chemical		Marketing and Midstream			Corporate and Eliminations				Total
Year ended December 31, 2019
Net sales	$	13,423		$	4,102	$	4,132		$	(1,264	)		$	20,393
Income (loss) from continuing operations before income taxes	$	2,352	(a)	$	799	$	241	(b)	$	(3,206	)	(c)	$	186
Income tax expense	—			—		—			(693		)	(d)	(693		)
Income (loss) from continuing operations	$	2,352		$	799	$	241		$	(3,899	)		$	(507	)
Investments in unconsolidated entities	$	181		$	689	$	5,519		$	—			$	6,389
Property, plant and equipment additions(e)	$	5,559		$	272	$	475		$	135			$	6,441
Depreciation, depletion and amortization	$	4,994		$	368	$	563		$	56			$	5,981
Total assets	$	77,936		$	4,361	$	17,055		$	9,978			$	109,330
Year ended December 31, 2018
Net sales	$	10,441		$	4,657	$	3,656		$	(930	)		$	17,824
Income (loss) from continuing operations before income taxes	$	2,442	(a)	$	1,159	$	2,802	(b)	$	(795	)	(c)	$	5,608
Income tax expense	—			—		—			(1,477		)	(d)	(1,477		)
Income (loss) from continuing operations	$	2,442		$	1,159	$	2,802		$	(2,272	)		$	4,131
Investments in unconsolidated entities	$	—		$	733	$	947		$	—			$	1,680
Property, plant and equipment additions(e)	$	4,443		$	277	$	221		$	79			$	5,020
Depreciation, depletion and amortization	$	3,254		$	354	$	331		$	38			$	3,977
Total assets	$	24,874		$	4,359	$	11,087		$	3,534			$	43,854
Year ended December 31, 2017
Net sales	$	7,870		$	4,355	$	1,157		$	(874	)		$	12,508
Income (loss) from continuing operations before income taxes	$	1,111	(a)	$	822	$	85	(b)	$	(690	)	(c)	$	1,328
Income tax expense	—			—		—			(17		)	(d)	(17		)
Income (loss) from continuing operations	$	1,111		$	822	$	85		$	(707	)		$	1,311
Investments in unconsolidated entities	$	—		$	771	$	739		$	5			$	1,515
Property, plant and equipment additions(e)	$	2,968		$	323	$	296		$	64			$	3,651
Depreciation, depletion and amortization	$	3,269		$	352	$	340		$	41			$	4,002
Total assets	$	23,595		$	4,364	$	11,775		$	2,292			$	42,026

^(a)  The 2019 amount included a net gain on sale of $475 million related to Occidental’s joint venture with Ecopetrol in the Midland Basin and sale of real estate assets, a $285 million impairment charge associated with domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and a $39 million charge related to Occidental’s mutually agreed early termination of its Qatar ISSD contract. The 2018 amount included $416 million for the impairment of proved oil properties and inventory in Qatar ISND and ISSD due to the decline in oil prices. The 2017 amount included pre-tax asset sale gains of $655 million primarily related to South Texas and non-core acreage in the Permian basin and $397 million for the impairment of non-core proved and unproved Permian acreage.

^(b)  The 2019 amount included a $1 billion charge as a result of recording Occidental’s investment in WES at fair value as of December 31, 2019 upon the loss of control, a $114 million gain on the sale of an equity investment in Plains and a $30 million mark-to-market gain on an interest rate swap for WES. The 2018 amount included pre-tax asset sale gains of $907 million on the sale of non-core domestic midstream assets. The 2017 amount included pre-tax charges of $120 million related to asset impairments of idled facilities.

^(c)  The 2019 amount included corporate transactions related to the Acquisition including charges of $1.0 billion related to employee severance and related costs, $401 million related to crucial seismic data and $213 million for bank, legal and consulting fees. There were no significant corporate transactions and events affecting 2018 and 2017 results. The tax effect of these pre-tax adjustments was a $245 million benefit in 2019, and $198 million expense and $392 million expense in 2018 and 2017, respectively.

^(d)  Included all foreign and domestic income taxes from continuing operations.

^(e)  Included capital expenditures and capitalized interest, but excluded acquisition and disposition of assets.

106 OXY 2019 FORM 10-K

FINANCIAL STATEMENTS FOOTNOTES

GEOGRAPHIC AREAS

	Property, plant and equipment, net
millions	2019		2018		2017
United States	$	72,808	$	23,594	$	22,863
International
United Arab Emirates	3,887		4,051		4,241
Oman	2,115		2,048		1,962
Colombia	1,010		927		807
Qatar	562		741		1,236
Other International	87		76		65
Total International	7,661		7,843		8,311
Total	$	80,469	$	31,437	$	31,174

OXY 2019 FORM 10-K 107

Supplemental Quarterly Information (Unaudited)

Quarterly Financial Data Occidental Petroleum Corporation and Subsidiaries

millions except per-share amounts	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2019
Segment net sales
Oil and gas	$	2,351		$	2,718		$	3,821		$	4,533
Chemical	1,059			998			1,071			974
Marketing and Midstream(a)	816			909			1,163			1,244
Eliminations	(222		)	(205		)	(368		)	(469		)
Net sales	$	4,004		$	4,420		$	5,687		$	6,282
Gross profit	$	1,210		$	1,449		$	1,422		$	1,287
Segment earnings
Oil and gas	$	484		$	726		$	221		$	921
Chemical	265			208			207			119
Marketing and Midstream(a)	279			331			400			(769		)
Total segment earnings	$	1,028		$	1,265		$	828		$	271
Unallocated corporate items
Interest expense, net	(83		)	(143		)	(360		)	(416		)
Income taxes	(225		)	(306		)	(116		)	(46		)
Other	(89		)	(181		)	(1,089		)	(845		)
Income (loss) from continuing operations	$	631		$	635		$	(737	)	$	(1,036	)
Discontinued operates, net of taxes	—			—			(15		)	—
Net Income (loss)	$	631		$	635		$	(752	)	$	(1,036	)
Less: Net income attributable to noncontrolling interests	—			—			(42		)	(103		)
Less: Preferred stock dividend	—			—			(118		)	(200		)
Net income (loss) attributable to common stockholders	$	631		$	635		$	(912	)	$	(1,339	)
Basic earnings (loss) per common share	$	0.84		$	0.84		$	(1.08	)	$	(1.50	)
Diluted earnings (loss) per common share	$	0.84		$	0.84		$	(1.08	)	$	(1.50	)
Dividends per common share	$	0.78		$	0.78		$	0.79		$	0.79
2018
Segment net sales
Oil and gas	$	2,454		$	2,531		$	2,889		$	2,567
Chemical	1,154			1,176			1,185			1,142
Marketing and Midstream	389			603			1,367			1,297
Eliminations	(234		)	(227		)	(225		)	(244		)
Net sales	$	3,763		$	4,083		$	5,216		$	4,762
Gross profit	$	1,371		$	1,556		$	2,297		$	1,616
Segment earnings
Oil and gas	$	750		$	780		$	767		$	145
Chemical	298			317			321			223
Marketing and Midstream	179			250			1,698			675
Total segment earnings	$	1,227		$	1,347		$	2,786		$	1,043
Unallocated corporate items
Interest expense, net	(92		)	(91		)	(92		)	(81		)
Income taxes	(339		)	(302		)	(710		)	(126		)
Other	(88		)	(106		)	(115		)	(130		)
Net income attributable to common stockholders	$	708		$	848		$	1,869		$	706
Basic earnings per common share	$	0.92		$	1.10		$	2.44		$	0.93
Diluted earnings per common share	$	0.92		$	1.10		$	2.44		$	0.93
Dividends per common share	$	0.77		$	0.77		$	0.78		$	0.78

^(a)  Marketing and Midstream segment net sales and earnings include the results of WES from the Acquisition date to the loss of control date.

108 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

Supplemental Oil and Gas Information

OIL AND GAS RESERVES

The following tables set forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of oil (including condensate), NGL and natural gas and changes in such quantities. Proved oil, NGL 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, NGL 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. The following table shows the pricing used in the reserve analysis for the periods presented:

	2019	2018	2017
Average WTI oil price (per barrel)	$55.69	$65.56	$51.34
Average Brent price (per barrel)	$63.03	$72.20	$54.93
Average Henry Hub natural gas price (per MMBtu)	$2.58	$3.10	$2.98

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 oil, natural gas and NGL fluctuate widely. Historically, the markets for oil, natural gas, NGL and refined products have been volatile and may continue to be volatile in the future. Prolonged or further declines in oil, natural gas and NGL 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.

Proved undeveloped reserves in the Permian Basin are supported by a five-year detailed field-level development plan, which includes the timing, location and capital commitment of the wells to be drilled. Only proved undeveloped reserves which are reasonably certain to be drilled within five years of booking and are supported by a final investment decision to drill them are included in the development plan. A portion of the proved undeveloped reserves associated with international operations are expected to be developed beyond the five years and are tied to approved long-term development plans.

109 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

OIL RESERVES^(a) 

millions of barrels (MMbbl)	United States		Latin America		Middle East (b)		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2016	960		71		326		1,357
Revisions of previous estimates	66		14		33		113
Improved recovery	97		8		17		122
Extensions and discoveries	—		—		5		5
Purchases of proved reserves	70		—		—		70
Sales of proved reserves	(13	)	—		—		(13	)
Production	(73	)	(11	)	(55	)	(139	)
Balance at December 31, 2017	1,107		82		326		1,515
Revisions of previous estimates	15		(2	)	(7	)	6
Improved recovery	135		23		31		189
Extensions and discoveries	—		4		2		6
Purchases of proved reserves	32		—		—		32
Sales of proved reserves	(12	)	—		—		(12	)
Production	(91	)	(11	)	(51	)	(153	)
Balance at December 31, 2018	1,186		96		301		1,583
Revisions of previous estimates (c)	(154	)	3		15		(136	)
Improved recovery	128		12		25		165
Extensions and discoveries	37		2		2		41
Purchases of proved reserves (d)	545		—		—		545
Sales of proved reserves	(17	)	—		—		(17	)
Production	(155	)	(12	)	(44	)	(211	)
Balance at December 31, 2019	1,570		101		299		1,970
PROVED DEVELOPED RESERVES
December 31, 2016	670		69		298		1,037
December 31, 2017	772		77		279		1,128
December 31, 2018	843		77		240		1,160
December 31, 2019 (e)	1,206		76		226		1,508
PROVED UNDEVELOPED RESERVES
December 31, 2016	290		2		28		320
December 31, 2017	335		5		47		387
December 31, 2018	343		19		61		423
December 31, 2019	364		25		73		462

^(a)  Excluded reserve amounts related to the Africa Assets.

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

^(c)  Revisions of previous estimates in 2019 primarily related to negative price revisions, changes to development plans and reservoir performance in the Permian Basin.

^(d)  Purchases of proved reserves in 2019 related to acquired reserves through the Acquisition.

^(e)  Approximately 11% of the proved developed reserves at December 31, 2019, are nonproducing, primarily associated with Oman, Permian EOR and DJ Basin.

110 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

NGL RESERVES^(a) 

millions of barrels (MMbbl)	United States		Latin America	Middle East		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2016	219		—	201		420
Revisions of previous estimates	11		—	(2	)	9
Improved recovery	23		—	10		33
Extensions and discoveries	—		—	—		—
Purchases of proved reserves	21		—	—		21
Sales of proved reserves	(7	)	—	—		(7	)
Production	(20	)	—	(11	)	(31	)
Balance at December 31, 2017	247		—	198		445
Revisions of previous estimates	7		—	15		22
Improved recovery	47		—	—		47
Extensions and discoveries	—		—	—		—
Purchases of proved reserves	11		—	—		11
Sales of proved reserves	(3	)	—	—		(3	)
Production	(25	)	—	(11	)	(36	)
Balance at December 31, 2018	284		—	202		486
Revisions of previous estimates (b)	(21	)	—	10		(11	)
Improved recovery	58		—	—		58
Extensions and discoveries	11		—	—		11
Purchases of proved reserves (c)	267		—	—		267
Sales of proved reserves	(7	)	—	—		(7	)
Production	(52	)	—	(12	)	(64	)
Balance at December 31, 2019	540		—	200		740
PROVED DEVELOPED RESERVES
December 31, 2016	149		—	164		313
December 31, 2017	161		—	153		314
December 31, 2018	196		—	145		341
December 31, 2019  (d)	406		—	141		547
PROVED UNDEVELOPED RESERVES
December 31, 2016	70		—	37		107
December 31, 2017	86		—	45		131
December 31, 2018	88		—	57		145
December 31, 2019	134		—	59		193

^(a)  Excluded reserve amounts related to the Africa Assets.

^(b)  Revisions of previous estimates in 2019 primarily related to negative price revisions, changes to development plans and reservoir performance in the Permian Basin and DJ Basin.

^(c)  Purchases of proved reserves in 2019 related to acquired reserves through the Acquisition.

^(d)  Approximately 6% of the proved developed reserves at December 31, 2019, are nonproducing, primarily associated with Permian EOR and DJ Basin.

OXY 2019 FORM 10-K 111

Supplemental Oil and Gas Information (Unaudited)

NATURAL GAS RESERVES^(a) 

billions of cubic feet (Bcf)	United States		Latin America		Middle East (b)		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2016	1,045		6		2,723		3,774
Revisions of previous estimates	197		8		(33	)	172
Improved recovery	167		1		106		274
Extensions and discoveries	—		—		3		3
Purchases of proved reserves	50		—		—		50
Sales of proved reserves	(146	)	—		—		(146	)
Production	(108	)	(3	)	(185	)	(296	)
Balance at December 31, 2017	1,205		12		2,614		3,831
Revisions of previous estimates	(25	)	—		191		166
Improved recovery	329		1		17		347
Extensions and discoveries	—		—		4		4
Purchases of proved reserves	69		—		—		69
Sales of proved reserves	(14	)	—		—		(14	)
Production	(119	)	(2	)	(187	)	(308	)
Balance at December 31, 2018	1,445		11		2,639		4,095
Revisions of previous estimates (c)	(409	)	(1	)	90		(320	)
Improved recovery	393		2		30		425
Extensions and discoveries	59		2		3		64
Purchases of proved reserves (d)	2,996		—		—		2,996
Sales of proved reserves	(30	)	—		—		(30	)
Production	(326	)	(2	)	(202	)	(530	)
Balance at December 31, 2019	4,128		12		2,560		6,700
PROVED DEVELOPED RESERVES
December 31, 2016	708		6		2,324		3,038
December 31, 2017	782		11		2,131		2,924
December 31, 2018	978		11		2,015		3,004
December 31, 2019  (e)	3,198		11		1,996		5,205
PROVED UNDEVELOPED RESERVES
December 31, 2016	337		—		399		736
December 31, 2017	423		1		483		907
December 31, 2018	467		—		624		1,091
December 31, 2019	930		1		564		1,495

^(a)  Excluded reserve amounts related to the Africa Assets.

^(b)  Approximately one-third of Middle East proved reserves relate to PSCs and other similar economic arrangements.

^(c)  Revisions of previous estimates in 2019 primarily related to negative price revisions, changes to development plans and reservoir performance in the Permian Basin.

^(d)  Purchases of proved reserves in 2019 related to acquired reserves through the Acquisition.

^(e)  Approximately 4% of the proved developed reserves at December 31, 2019, are nonproducing, primarily associated with Permian EOR and DJ Basin.

112 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

TOTAL RESERVES^(a) 

millions of BOE (MMBOE) (b)	United States		Latin America		Middle East		Total(c)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2016	1,353		72		981		2,406
Revisions of previous estimates	109		16		26		151
Improved recovery	149		8		44		201
Extensions and discoveries	—		—		5		5
Purchases of proved reserves	99		—		—		99
Sales of proved reserves	(44	)	—		—		(44	)
Production	(111	)	(12	)	(97	)	(220	)
Balance at December 31, 2017	1,555		84		959		2,598
Revisions of previous estimates	18		(2	)	40		56
Improved recovery	237		23		34		294
Extensions and discoveries	—		4		3		7
Purchases of proved reserves	54		—		—		54
Sales of proved reserves	(17	)	—		—		(17	)
Production	(136	)	(11	)	(93	)	(240	)
Balance at December 31, 2018	1,711		98		943		2,752
Revisions of previous estimates (d)	(243	)	3		40		(200	)
Improved recovery	251		12		30		293
Extensions and discoveries	58		2		3		63
Purchases of proved reserves (e)	1,311		—		—		1,311
Sales of proved reserves	(29	)	—		—		(29	)
Production	(261	)	(12	)	(90	)	(363	)
Balance at December 31, 2019	2,798		103		926		3,827
PROVED DEVELOPED RESERVES
December 31, 2016	937		70		849		1,856
December 31, 2017	1,063		79		786		1,928
December 31, 2018	1,202		79		721		2,002
December 31, 2019(f)	2,145		78		700		2,923
PROVED UNDEVELOPED RESERVES
December 31, 2016	416		2		132		550
December 31, 2017	492		5		173		670
December 31, 2018	509		19		222		750
December 31, 2019	653		25		226		904

^(a)  Excluded reserve amounts related to the Africa Assets.

^(b)  Natural gas volumes have been converted to barrels of oil equivalent (BOE) based on an energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil.  

^(c)  Included proved reserves related to PSCs and other similar economic arrangements of 0.5 billion BOE at December 31, 2019, 2018, 2017, and 2016.

^(d)  Revisions of previous estimates in 2019 primarily related to negative price revisions, changes to development plans and reservoir performance in the Permian Basin.

^(e)  Purchases of proved reserves in 2019 related to acquired reserves through the Acquisition.

^(f)  Approximately 8% of the proved developed reserves at December 31, 2019, are nonproducing, primarily associated with Oman, Permian EOR and DJ Basin.

OXY 2019 FORM 10-K 113

Supplemental Oil and Gas Information (Unaudited)

Reserves of Assets Held for Sale

The table below shows proved developed and undeveloped reserves related to Ghana and Algeria that were presented as held for sale at December 31, 2019:

	Oil (MMbbl)	NGL(MMbbl)	Natural Gas (Bcf)	Total (MMBOE)
PROVED DEVELOPED RESERVES	99	7	19	109
PROVED UNDEVELOPED RESERVES	14	—	11	16

CAPITALIZED COSTS

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

millions	United States			Latin America			Middle East			Total
December 31, 2019
Proved properties	$	59,658		$	3,667		$	11,787		$	75,112
Unproved properties	30,301			36			432			30,769
Total capitalized costs (a,b)	89,959			3,703			12,219			105,881
Proved properties depreciation, depletion and amortization	(20,961		)	(2,643		)	(8,853		)	(32,457		)
Unproved properties valuation	(1,025		)	(27		)	(170		)	(1,222		)
Total Accumulated depreciation, depletion and amortization	(21,986		)	(2,670		)	(9,023		)	(33,679		)
Net capitalized costs	$	67,973		$	1,033		$	3,196		$	72,202
December 31, 2018
Proved properties	$	35,717		$	3,436		$	17,302		$	56,455
Unproved properties	1,900			43			401			2,344
Total capitalized costs (a)	37,617			3,479			17,703			58,799
Proved properties depreciation, depletion and amortization	(17,188		)	(2,514		)	(14,286		)	(33,988		)
Unproved properties valuation	(1,200		)	(27		)	(85		)	(1,312		)
Total Accumulated depreciation, depletion and amortization	(18,388		)	(2,541		)	(14,371		)	(35,300		)
Net capitalized costs	$	19,229		$	938		$	3,332		$	23,499
December 31, 2017
Proved properties	$	31,091		$	3,194		$	16,582		$	50,867
Unproved properties	2,094			53			394			2,541
Total capitalized costs (a)	33,185			3,247			16,976			53,408
Proved properties depreciation, depletion and amortization	(14,609		)	(2,412		)	(13,196		)	(30,217		)
Unproved properties valuation	(1,166		)	(27		)	—			(1,193		)
Total Accumulated depreciation, depletion and amortization	(15,775		)	(2,439		)	(13,196		)	(31,410		)
Net capitalized costs	$	17,410		$	808		$	3,780		$	21,998

^(a)  Included acquisition costs, development costs, capitalized interest and asset retirement obligations. Excluded capitalized costs related to Africa Assets.

^(b)  $48.4 billion of capitalized costs are associated with the Acquisition.

114 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

COSTS INCURRED

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

millions	United States		Latin America		Middle East		Total
FOR THE YEAR ENDED DECEMBER 31, 2019(a)
Property acquisition costs
Proved properties	$	19,567	$	6	$	—	$	19,573
Unproved properties	29,042		1		11		29,054
Exploration costs	307		58		141		506
Development costs	4,449		196		563		5,208
Costs incurred	$	53,365	$	261	$	715	$	54,341
FOR THE YEAR ENDED DECEMBER 31, 2018
Property acquisition costs
Proved properties	$	428	$	—	$	—	$	428
Unproved properties	46		4		2		52
Exploration costs	196		42		44		282
Development costs	3,387		203		698		4,288
Costs incurred	$	4,057	$	249	$	744	$	5,050
FOR THE YEAR ENDED DECEMBER 31, 2017
Property acquisition costs
Proved properties	$	880	$	—	$	1	$	881
Unproved properties	32		—		—		32
Exploration costs	163		39		54		256
Development costs	1,981		157		582		2,720
Costs incurred	$	3,056	$	196	$	637	$	3,889

^(a)  Excluded costs incurred related to Africa Assets.

OXY 2019 FORM 10-K 115

Supplemental Oil and Gas Information (Unaudited)

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:

millions	United States			Latin America		Middle East		Total
FOR THE YEAR ENDED DECEMBER 31, 2019
Revenues (a)	$	9,497		$	703	$	3,335	$	13,535
Lease operating costs	2,271			163		904		3,338
Transportation costs	647			5		78		730
Other operating expenses	1,125			51		200		1,376
Depreciation, depletion and amortization	4,113			135		746		4,994
Taxes other than on income	651			8		—		659
Exploration expenses	99			45		102		246
Oil and gas mark-to-market - Collars and CO2	15			—		—		15
Pretax income before impairments and other charges	576			296		1,305		2,177
Asset impairments and other charges	288			—		39		327
Pretax income	288			296		1,266		1,850
Income tax expense (b)	74			135		634		843
Results of operations(c)	$	214		$	161	$	632	$	1,007
FOR THE YEAR ENDED DECEMBER 31, 2018
Revenues (a)	$	5,747		$	731	$	3,963	$	10,441
Lease operating costs	1,675			151		939		2,765
Transportation costs	11			3		98		112
Other operating expenses	676			49		186		911
Depreciation, depletion and amortization	2,321			102		831		3,254
Taxes other than on income	407			6		—		413
Exploration expenses	64			19		27		110
Oil and gas mark-to-market - CO2	(4		)	—		—		(4		)
Pretax income before impairments and other charges	597			401		1,882		2,880
Asset impairments and other charges	32			—		416		448
Pretax income	565			401		1,466		2,432
Income tax expense (benefit) (b)	(131		)	174		925		968
Results of operations	$	696		$	227	$	541	$	1,464
FOR THE YEAR ENDED DECEMBER 31, 2017
Revenues (a)	$	4,047		$	570	$	3,253	$	7,870
Lease operating costs	1,463			151		849		2,463
Transportation costs	11			4		101		116
Other operating expenses	621			51		166		838
Depreciation, depletion and amortization	2,549			124		596		3,269
Taxes other than on income	273			9		—		282
Exploration expenses	28			7		47		82
Oil and gas mark-to-market - CO2	(36		)	—		—		(36		)
Pretax income (loss) before impairments and other charges	(862		)	224		1,494		856
Asset impairments and other charges	397			4		—		401
Pretax income (loss)	(1,259		)	220		1,494		455
Income tax expense (benefit) (b)	(695		)	120		690		115
Results of operations	$	(564	)	$	100	$	804	$	340

^(a)  Revenues are net of royalty payments.

^(b)  U.S. federal income taxes reflect certain expenses related to oil and gas activities allocated for U.S. income tax purposes . These amounts are computed using the statutory rate in effect during the period.

^(c)  The 2019 results of operations excluded amounts related to Africa Assets.

116 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

$/BOE (a)	United States			Latin America		Middle East		Total
FOR THE YEAR ENDED DECEMBER 31, 2019
Revenues (b)	$	36.43		$	56.70	$	36.94	$	37.25
Lease operating costs	8.71			13.18		10.01		9.19
Transportation costs	2.48			0.34		0.87		2.01
Other operating expenses	4.32			4.15		2.21		3.79
Depreciation, depletion and amortization	15.78			10.85		8.27		13.74
Taxes other than on income	2.50			0.63		—		1.81
Exploration expenses	0.38			3.66		1.13		0.68
Oil and gas mark-to-market - Collars and CO2	0.06			—		—		0.04
Pretax income before impairments and other charges	2.20			23.89		14.45		5.99
Asset impairments and other charges	1.11			—		0.43		0.90
Pretax income	1.09			23.89		14.02		5.09
Income tax expense(c)	0.29			10.90		7.01		2.32
Results of operations(d)	$	0.80		$	12.99	$	7.01	$	2.77
FOR THE YEAR ENDED DECEMBER 31, 2018
Revenues (b)	$	42.30		$	63.37	$	42.78	$	43.50
Lease operating costs	12.33			13.08		10.14		11.52
Transportation costs	0.08			0.24		1.06		0.47
Other operating expenses	4.98			4.24		2.01		3.79
Depreciation, depletion and amortization	17.08			8.88		8.96		13.56
Taxes other than on income	3.00			0.52		—		1.72
Exploration expenses	0.47			1.65		0.29		0.46
Oil and gas mark-to-market - CO2	(0.03		)	—		—		(0.01		)
Pretax income before impairments and other charges	4.39			34.76		20.32		11.99
Asset impairments and other charges	0.24			—		4.49		1.87
Pretax income	4.15			34.76		15.83		10.12
Income tax expense (benefit) (c)	(0.96		)	15.08		9.99		4.03
Results of operations	$	5.11		$	19.68	$	5.84	$	6.09
FOR THE YEAR ENDED DECEMBER 31, 2017
Revenues (b)	$	36.50		$	47.79	$	33.51	$	35.79
Lease operating costs	13.19			12.66		8.75		11.20
Transportation costs	0.10			0.33		1.04		0.53
Other operating expenses	5.60			4.28		1.71		3.81
Depreciation, depletion and amortization	22.99			10.37		6.14		14.87
Taxes other than on income	2.47			0.75		—		1.28
Exploration expenses	0.25			0.59		0.48		0.37
Oil and gas mark-to-market - CO2	(0.32		)	—		—		(0.16		)
Pretax income before impairments and other charges	(7.78		)	18.81		15.39		3.89
Asset impairments and other charges	3.58			0.34		—		1.82
Pretax income (loss)	(11.36		)	18.47		15.39		2.07
Income tax expense (benefit) (c)	(6.27		)	10.06		7.11		0.52
Results of operations	$	(5.09	)	$	8.41	$	8.28	$	1.55

^(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.

^(b)  Revenues are net of royalty payments.

^(c)  U.S. federal income taxes reflect certain expenses related to oil and gas activities allocated for U.S. income tax purposes . These amounts are computed using the statutory rate in effect during the period.

^(d)  The 2019 results of operations excluded amounts related to Africa Assets.

OXY 2019 FORM 10-K 117

Supplemental Oil and Gas Information (Unaudited)

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, 2019, 2018, and 2017, respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities to develop and produce proved reserves at year end.

	2019	2018	2017
Average WTI oil price (per barrel)	$55.69	$65.56	$51.34
Average Brent price (per barrel)	$63.03	$72.20	$54.93
Average Henry Hub natural gas price (per MMBtu)	$2.58	$3.10	$2.98

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% discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2019, 2018, and 2017. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

millions	United States			Latin America			Middle East			Total
AT DECEMBER 31, 2019
Future cash inflows	$	97,293		$	5,803		$	28,715		$	131,811
Future costs
Production costs and other operating	(47,685		)	(2,824		)	(9,786		)	(60,295		)
Development costs (a)	(13,137		)	(553		)	(2,543		)	(16,233		)
Future income tax expense	(4,097		)	(687		)	(2,559		)	(7,343		)
Future net cash flows	32,374			1,739			13,827			47,940
10% discount factor	(12,427		)	(701		)	(6,819		)	(19,947		)
Standardized measure of discounted future net cash flows (b)	$	19,947		$	1,038		$	7,008		$	27,993
AT DECEMBER 31, 2018
Future cash inflows	$	75,313		$	6,104		$	31,158		$	112,575
Future costs
Production costs and other operating	(33,373		)	(2,673		)	(9,609		)	(45,655		)
Development costs (a)	(9,450		)	(377		)	(2,136		)	(11,963		)
Future income tax expense	(4,150		)	(959		)	(3,524		)	(8,633		)
Future net cash flows	28,340			2,095			15,889			46,324
10% discount factor	(14,288		)	(846		)	(7,729		)	(22,863		)
Standardized measure of discounted future net cash flows	$	14,052		$	1,249		$	8,160		$	23,461
AT DECEMBER 31, 2017
Future cash inflows	$	59,289		$	3,961		$	25,662		$	88,912
Future costs
Production costs and other operating	(29,318		)	(1,915		)	(9,349		)	(40,582		)
Development costs (a)	(7,986		)	(238		)	(2,199		)	(10,423		)
Future income tax expense	(1,838		)	(543		)	(2,906		)	(5,287		)
Future net cash flows	20,147			1,265			11,208			32,620
10% discount factor	(10,951		)	(423		)	(5,026		)	(16,400		)
Standardized measure of discounted future net cash flows	$	9,196		$	842		$	6,182		$	16,220

^(a)  Included asset retirement costs.

^(b)  Excluded discounted future net cash flows of $2.0 billion related to Occidental’s Africa Assets.

118 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES

millions	2019			2018			2017
Balance at January 1	$	23,461		$	16,220		$	9,713
Sales and transfers of oil and gas produced, net of production costs and other operating expenses	(8,884		)	(7,828		)	(5,362		)
Net change in prices received per barrel, net of production costs and other operating expenses	(6,823		)	9,482			7,598
Extensions, discoveries and improved recovery, net of future production and development costs	2,607			3,378			1,534
Change in estimated future development costs	(1,636		)	(3,463		)	(1,283		)
Revisions of quantity estimates	(1,769		)	664			966
Previously estimated development costs incurred during the period	3,297			1,943			1,643
Accretion of discount	2,276			1,551			922
Net change in income taxes	2,905			(1,182		)	(528		)
Purchases and sales of reserves in place, net	9,945			347			688
Changes in production rates and other	2,614			2,349			329
Net change	4,532			7,241			6,507
Balance at December 31	$	27,993		$	23,461		$	16,220

AVERAGE SALES PRICE

The following table sets forth, for each year in the three-year period ended December 31, 2019, Occidental’s approximate average sales prices in continuing operations:

	United States		Latin America		Middle East		Total
2019
Oil ($/bbl)	$	54.31	$	57.26	$	61.96	$	56.09
NGL ($/bbl)	$	16.03	$	—	$	21.31	$	17.06
Gas ($/Mcf)	$	1.31	$	7.01	$	1.59	$	1.45
2018
Oil ($/bbl)	$	56.30	$	64.32	$	67.69	$	60.64
NGL ($/bbl)	$	27.64	$	—	$	23.20	$	26.25
Gas ($/Mcf)	$	1.59	$	6.43	$	1.58	$	1.62
2017
Oil ($/bbl)	$	47.91	$	48.50	$	50.38	$	48.93
NGL ($/bbl)	$	23.67	$	—	$	18.05	$	21.63
Gas ($/Mcf)	$	2.31	$	5.08	$	1.52	$	1.84

OXY 2019 FORM 10-K 119

Supplemental Oil and Gas Information (Unaudited)

NET PRODUCTIVE AND DRY— EXPLORATORY AND DEVELOPMENT WELLS COMPLETED

The following table sets forth, for each year in the three-year period ended December 31, 2019, Occidental’s net productive and dry exploratory and development wells completed:

	United States	Latin America	Middle East	Total
2019
Oil
Exploratory	22	—	7	29
Development	422	68	129	619
Gas
Exploratory	—	2	5	7
Development	2	—	2	4
Dry
Exploratory	1	3	6	10
Development	—	1	—	1
2018
Oil
Exploratory	11	2	5	18
Development	267	54	138	459
Gas
Development	3	—	1	4
Dry
Exploratory	—	2	3	5
2017
Oil
Exploratory	14	1	5	20
Development	201	51	105	357
Gas
Development	2	—	1	3
Dry
Exploratory	—	—	3	3

PRODUCTIVE OIL AND GAS WELLS

The following table sets forth, as of December 31, 2019, Occidental’s productive oil and gas wells (both producing and capable of production):

Wells at December 31, 2019 (a)	United States			Latin America		Middle East			Total
Oil
Gross (b)	20,976	(1,196	)	1,881	—	2,579	—		25,436	(1,196	)
Net (c)	17,304	(1,076	)	954	—	1,205	—		19,463	(1,076	)
Gas
Gross (b)	9,596	(2,386	)	35	—	113	(2	)	9,744	(2,388	)
Net (c)	8,056	(2,138	)	33	—	58	(2	)	8,147	(2,140	)

^(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.

120 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

PARTICIPATION IN WELLS BEING DRILLED OR PENDING COMPLETION

The following table sets forth, as of December 31, 2019, Occidental’s participation in exploratory and development wells being drilled:

	United States	Latin America	Middle East	Total
Exploratory and development wells being drilled
Gross	73	2	23	98
Net	57	2	13	72
Exploratory and development wells pending completion (a,b)
Gross	359	—	—	359
Net	294	—	—	294

^(a)  Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

^(b)  There were 138 MMBOE of PUDs primarily assigned to U.S. onshore development wells suspended or waiting on completion at December 31, 2019, Occidental expects to convert all of these PUDs reserves to developed status within five years of their initial disclosure.

At December 31, 2019, Occidental was participating in 109 pressure-maintenance projects, mostly waterfloods, in the United States, 9 in Latin America, and 44 in the Middle East.

OIL AND GAS ACREAGE

The following table sets forth, as of December 31, 2019, Occidental’s holdings of developed and undeveloped oil and gas acreage:

thousands	United States	Latin America	Middle East	Total
Developed (a)
Gross (b)	6,782	146	589	7,517
Net (c)	4,208	97	215	4,520
Undeveloped (d)
Gross (b)	1,992	1,853	5,536	9,381
Net (c)	1,341	996	4,717	7,054
Fee Mineral Ownership (e)
Gross (b)	12,515	—	—	12,515
Net (c)	8,810	—	—	8,810

^(a)  Acres spaced or assigned to productive wells.

^(b)  Total acres in which interests are held.

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

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

^(e)  Occidental’s fee mineral acreage is primarily undeveloped.

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 the contractual expiration date. 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.

OXY 2019 FORM 10-K 121

Supplemental Oil and Gas Information (Unaudited)

OIL, NGL AND NATURAL GAS SALES VOLUMES PER DAY

The following tables set forth the sales volumes from ongoing operations of oil, NGL and natural gas per day for each of the three years in the period ended December 31, 2019. The differences between the sales and production volumes per day are negligible and are generally due to the timing of shipments at Occidental’s international locations where product is loaded onto tankers. Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil. 

Sales per Day from Ongoing Operations (MBOE/d)	2019	2018	2017
United States
Permian Resources	355	214	141
Permian EOR	154	154	150
DJ Basin	120	—	—
Gulf of Mexico	58	—	—
Other Domestic	27	4	5
Total	714	372	296
Latin America	34	32	33
Middle East
Al Hosn Gas	82	73	71
Dolphin	42	40	42
Oman	89	86	95
Qatar	35	55	58
Total	248	254	266
Total Sales from Ongoing Operations (MBOE/d)	996	658	595
Sold domestic operations	—	—	8
Discontinued operations - Africa Assets	33	—	—
Total Sales (MBOE/d)	1,029	658	603

122 OXY 2019 FORM 10-K

Supplemental Oil and Gas Information (Unaudited)

Sales per Day by Products from Ongoing Operations (MBOE/d)	2019	2018	2017
United States
Oil (Mbbl)
Permian Resources	207	132	85
Permian EOR	117	117	113
DJ Basin	46	—	—
Gulf of Mexico	48	—	—
Other Domestic	7	1	2
Total	425	250	200
NGL (Mbbl)
Permian Resources	74	38	26
Permian EOR	30	29	27
DJ Basin	28	—	—
Gulf of Mexico	4	—	—
Other Domestic	4	—	—
Total	140	67	53
Natural gas (MMcf)
Permian Resources	442	261	184
Permian EOR	44	50	57
DJ Basin	275	—	—
Gulf of Mexico	34	—	—
Other Domestic	98	16	18
Total	893	327	259
Latin America
Oil (Mbbl)	33	31	32
Natural gas (MMcf)	7	6	7
Middle East
Oil (Mbbl)
Al Hosn Gas	14	13	13
Dolphin	7	7	7
Oman	66	63	72
Qatar	35	55	58
Total	122	138	150
NGL (Mbbl)
Al Hosn Gas	26	23	23
Dolphin	8	8	8
Total	34	31	31
Natural gas (MMcf)
Al Hosn Gas	251	220	211
Dolphin	161	152	159
Oman	138	139	138
Total	550	511	508
Total Sales from Ongoing Operations (MBOE/d)	996	658	595

OXY 2019 FORM 10-K 123

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

			Additions
millions	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions (a)			Balance at End of Period
2019
Allowance for doubtful accounts	$	668	$	126	$	(6	)	$	—		$	788	(b)
Environmental, litigation and other reserves	$	994	$	182	$	1,408		$	(173	)	$	2,411	(c)
2018
Allowance for doubtful accounts	$	594	$	77	$	(3	)	$	—		$	668	(b)
Environmental, litigation, tax and other reserves	$	935	$	140	$	85		$	(166	)	$	994	(c)
2017
Allowance for doubtful accounts	$	558	$	37	$	(2	)	$	1		$	594	(b)
Environmental, litigation, tax and other reserves	$	997	$	45	$	53		$	(160	)	$	935	(c)

Note:  The amounts presented represent continuing operations.

^(a)  Primarily represents payments.

^(b)  Of these amounts, $22 million, $24 million and $18 million in 2019, 2018, and 2017, respectively, are classified as current.

^(c)  Of these amounts, $188 million, $146 million and $163 million in 2019, 2018, and 2017, respectively, are classified as current.

124 OXY 2019 FORM 10-K

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

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

ITEM 9A.    CONTROLS AND PROCEDURES

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

The management of Occidental Petroleum Corporation and its subsidiaries (Occidental) is responsible for establishing and maintaining adequate internal control over financial reporting. Occidental’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Occidental’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of Occidental’s assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that Occidental’s receipts and expenditures are being made only in accordance with authorizations of Occidental’s management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Occidental’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of Occidental’s internal control system as of December 31, 2019, 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, 2019, Occidental’s system of internal control over financial reporting is effective.

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

DISCLOSURE CONTROLS AND PROCEDURES

Occidental’s President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer supervised and participated in Occidental’s evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, Occidental’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer concluded that Occidental’s disclosure controls and procedures were effective as of December 31, 2019.

Except as described below, 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 2019 that has materially affected, or is reasonably likely to materially affect, Occidental’s internal control over financial reporting. The Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting is set forth in Item 8.

In the third quarter of 2019, Occidental started the process of integrating Anadarko into its operations and internal control processes, resulting in some of Anadarko’s historical internal controls being superseded by Occidental’s internal controls. Management will continue to integrate Anadarko’s historical internal controls over financial reporting with Occidental’s internal controls over financial reporting. This integration may lead to changes in Occidental’s or Anadarko’s historical internal controls over financial reporting in future fiscal periods. Occidental is also in the process of implementing a new Enterprise Resource Planning (ERP) system which was implemented in January 2020. Occidental intends to integrate Anadarko’s internal control processes into Occidental’s internal control processes in conjunction with implementation of the ERP system. Management expects the integration process to be completed during 2021.

ITEM 9B. OTHER INFORMATION

None.

OXY 2019 FORM 10-K 125

Part III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Occidental has adopted a Code of Business Conduct (Code). The Code applies to the President and Chief Executive Officer; Senior Vice President and Chief Financial Officer; Vice President, Chief Accounting 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 within four business days following the date of the amendment or waiver.

The list of Occidental’s executive officers and related information under “Information About Our 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 to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2019.

ITEM 11. EXECUTIVE COMPENSATION

The information under the caption “Compensation Discussion and Analysis - Compensation Committee Report” shall not be deemed to be “soliciting material,” or to be “filed” with the SEC, or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933. The information required by this Item 11 is incorporated herein by reference from Occidental’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2019.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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 80 million, of which approximately 6.6 million had been reserved for issuance through December 31, 2019. 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 reflected in column (a))
7,450,436 (1)		$79.98 (2)		52,452,301 (3)

⁽¹⁾  Included shares reserved to be issued pursuant to restricted stock units, stock options (Options), 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 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 stock appreciation rights (SARs) and 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 are forfeited or canceled, or correspond to the portion of any stock-based awards settled in cash.

The information required by this Item 12 is incorporated herein by reference from Occidental’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2019.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by this Item 13 is incorporated herein by reference from Occidental’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2019.

126 OXY 2019 FORM 10-K

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item 14 is incorporated herein by reference from Occidental’s definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2019.

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

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

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

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

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

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

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

(a) (3). Exhibits

2.1	Agreement and Plan of Merger, dated as of May 9, 2019, among Occidental Petroleum Corporation, Baseball Merger Sub 1, Inc. and Anadarko Petroleum Corporation (filed as Exhibit 2.1 to the Current Report on Form 8-K of Occidental filed on May 10, 2019, File No. 1-9210).
2.2	Purchase and Sale Agreement, dated as of August 3, 2019, between Occidental Petroleum Corporation and Total S.A. (filed as Exhibit 2.1 to the Current Report on Form 8-K of Occidental filed on August 5, 2019, 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 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 dated February 6, 2002, File No. 333-82246).
3.(ii)	Amended and Restated By-laws of Occidental Petroleum Corporation as of May 5, 2019 (filed as Exhibit 3.1 to the Current Report on Form 8-K of Occidental filed on May 6, 2019, File No. 1-9210).
3.(ii)(a)	Certificate of Designations with respect to the Cumulative Perpetual Preferred Stock, Series A (filed as Exhibit 3.1 to the Current Report on Form 8-K of Occidental filed on August 8, 2019, File No. 1-9210).
4.1	Description of Securities of Occidental Petroleum Corporation.
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% 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 10.38 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	Occidental Petroleum Corporation Savings Plan, Amended and Restated as of January 1, 2019.
10.2	Occidental Petroleum Corporation Modified Deferred Compensation Plan, Amended and Restated as of January 1, 2019 (filed as Exhibit 10.2 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2018, File No. 1-9210).
10.3	Occidental Petroleum Corporation Supplemental Retirement Plan II, Amended and Restated as of January 1, 2018 (filed as Exhibit 10.3 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2017, File No. 1-9210).
10.4	Form of 2018 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Total Shareholder Return Incentive Award (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2018, File No.1-9210).
10.5	Form of 2018 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Restricted Stock Unit Incentive Award (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2018, File No.1-9210).
10.6	Form of 2018 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Cash Return on Capital Employed Incentive Award (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2018, File No.1-9210).

OXY 2019 FORM 10-K 127

10.7	Form of Amendment to Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Notice of Grant of Performance Retention Incentive Award (filed as Exhibit 10.4 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2017, File No. 1-9210).
10.8	Occidental Petroleum Corporation Executive Incentive Compensation Plan, Amended and Restated as of January 1, 2016. (filed as Exhibit 10.4 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2016, File No. 1-9210).
10.9	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).
10.10	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).
10.11	Occidental Petroleum Corporation 2015 Long-Term Incentive Plan (filed as Exhibit 4.5 to the Registration Statement on Form S-8 of Occidental dated May 1, 2015, File No. 333-203801).
10.12	Form of Occidental Petroleum Corporation Amendment to Senior Executive Supplemental Life Insurance Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.13	Form of Occidental Petroleum Corporation Amendment to Senior Executive Survivor Benefit Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.14	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).
10.15	Second Amendment to the Occidental Petroleum Corporation 2015 Long-Term Incentive Plan (filed as Exhibit 4.5 to the Registration Statement on Form S-8 of Occidental filed May 4, 2018, File No. 333-224691).
10.16	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).
10.17	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).
10.18	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).
10.19	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 filed on October 14, 2010, File No. 1-9210).
10.20	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).
10.21	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).
10.22	Form of 2017 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan 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, 2017, File No. 1-9210).
10.23	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 filed on July 16, 2013, File No. 1-9210).
10.24	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 filed on July 26, 2013, File No. 1-9210).
10.25	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).
10.26	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).
10.27	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).
10.28	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).

128 OXY 2019 FORM 10-K

10.29	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).
10.30	Form of Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Cash Return on Capital Employed Incentive Award (applicable to annual grants made in 2019) (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the Quarterly Period ended March 31, 2019, File No. 1-9210).
10.31	Retention Agreement with Christopher O. Champion (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental filed on August 8, 2019, File No. 1-9210).
10.32	Anadarko Petroleum Corporation Retirement Restoration Plan (As Amended and Restated Effective as of December 31, 2019).
10.33	Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective August 8, 2019) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the Quarterly Period ended September 30, 2019, File No. 1-9210).
10.34	Anadarko Employee Savings Plan (As Amended and Restated Effective January 1, 2015) (filed as Exhibit 4.3 to the Post-Effective Amendment No.1 on Form S-8 to Form S-4 of Occidental filed on August 8, 2019, File No. 1-9210).
10.35	Termination Amendment to the Anadarko Employee Savings Plan (As Amended and Restated Effective January 1, 2015) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the Quarterly Period ended September 30, 2019, File No. 1-9210).
10.36	First Amendment to the Occidental Petroleum Corporation Savings Plan (As Amended and Restated Effective January 1, 2018) (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the Quarterly Period ended September 30, 2019, File No. 1-9210).
10.37	Kerr-McGee Corporation Benefits Restoration Plan (Amended and Restated Effective August 8, 2019) (filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q of Occidental for the Quarterly Period ended September 30, 2019, File No. 1-9210).
10.38	Anadarko Petroleum Corporation Deferred Compensation Plan (As Amended and Restated effective as of December 31, 2019).
10.39	Securities Purchase Agreement, dated April 30, 2019 between Occidental Petroleum Corporation and Berkshire Hathaway Inc. (including forms of the Certificate of Designations, Warrant and Registration Rights Agreement) (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental filed on May 3, 2019, File No. 1-9210).
10.40	Memorandum of Understanding, dated May 3, 2019, between Occidental Petroleum Corporation and TOTAL S.A. (filed as Exhibit 10.2 to the Registration Statement on Form S-4/A of Occidental dated July 3, 2019, File No. 333-232001).
10.41	Term Loan Agreement, dated as of June 3, 2019, among Occidental Petroleum Corporation, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental filed on August 8, 2019, File No. 1-9210).
10.42	Amended and Restated Revolving Credit Agreement, dated as of June 3, 2019, among Occidental Petroleum Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated August 8, 2019 (date of earliest event reported), filed August 8, 2019, File No. 1-9210).
21	List of subsidiaries of Occidental at December 31, 2019.
23.1	Consent of Independent Registered Public Accounting Firm.
23.2	Consent of Ryder Scott, Independent Petroleum Engineers.
23.3	Consent of Miller and Lents, Independent Petroleum Engineers.
31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Ryder Scott Company Process Review of the Estimated Future Proved Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Contracts as of December 31, 2019.
99.2	Procedures and Methods Review of Certain of Occidental Petroleum Corporation’s Proved Reserves and Future Net Cash Flows As of December 31, 2019.
101.INS	Inline XBRL Instance Document.
101.SCH	Inline XBRL Taxonomy Extension Schema Document.
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document.
104	Cover Page Interactive Data File - The cover page from Occidental Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2019 is formatted in Inline XBRL (included as Exhibit 101).

OXY 2019 FORM 10-K 129

ITEM 16. FORM 10-K SUMMARY

Not applicable.

130 OXY 2019 FORM 10-K

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

OCCIDENTAL PETROLEUM CORPORATION
By:	/s/ Vicki Hollub
	Vicki Hollub
	President and Chief Executive Officer

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

	Title	Date
/s/ Vicki Hollub	President, Chief Executive Officer	February 27, 2020
Vicki Hollub	and Director
/s/ Cedric W. Burgher	Senior Vice President and	February 27, 2020
Cedric W. Burgher	Chief Financial Officer
/s/ Christopher O. Champion	Vice President, Chief Accounting Officer	February 27, 2020
Christopher O. Champion	and Controller
/s/ Spencer Abraham	Director	February 27, 2020
Spencer Abraham
/s/ Eugene L. Batchelder	Chairman of the Board of Directors	February 27, 2020
Eugene L. Batchelder
/s/ Margaret M. Foran	Director	February 27, 2020
Margaret M. Foran
/s/ Carlos M. Gutierrez	Director	February 27, 2020
Carlos M. Gutierrez
/s/ William R. Klesse	Director	February 27, 2020
William R. Klesse
/s/ Jack B. Moore	Director	February 27, 2020
Jack B. Moore
/s/ Avedick B. Poladian	Director	February 27, 2020
Avedick B. Poladian
/s/ Robert M. Shearer	Director	February 27, 2020
Robert M. Shearer
/s/ Elisse B. Walter	Director	February 27, 2020
Elisse B. Walter

OXY 2019 FORM 10-K 131

EX-4.1

Exhibit 4.1

OCCIDENTAL PETROLEUM CORPORATION
DESCRIPTION OF SECURITIES

DESCRIPTION OF COMMON STOCK

General

The common stock of Occidental Petroleum Corporation (“Occidental,” “our” or “we”) is listed on the New York Stock Exchange (“NYSE”) under the symbol “OXY.” The following description of our common stock describes the material provisions of our common stock and does not purport to be complete. We urge you to read our Restated Certificate of Incorporation of Occidental Petroleum Corporation, as amended (“Certificate of Incorporation”), and our Amended and Restated By-laws of Occidental Petroleum Corporation (“Bylaws”), which are incorporated by reference as Exhibits 3.(i) and 3.(ii), respectively, to the Annual Report on Form 10-K of which this Exhibit 4.1 is a part.

Our Certificate of Incorporation authorizes our board of directors, without further stockholder action, to provide for the issuance of up to 1,100,000,000 shares of common stock, par value $0.20 per share. The common stock will, when issued, be fully paid and nonassessable.

Dividend Rights

Subject to the dividend rights of the holders of any outstanding series of preferred stock, the holders of shares of common stock will be entitled to receive dividends when, as and if declared by our board of directors. We will pay those dividends either in cash, shares of common stock, or otherwise, at the rate and on the date or dates as declared by our board of directors. Accruals of dividends will not bear interest. As a Delaware corporation, we are subject to statutory limitations on the declaration and payment of dividends.

Liquidation Rights

In the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs, holders of common stock will be entitled to share ratably in our assets that are legally available for distribution to stockholders after payment of liabilities, and after the payment in full of the amounts required to be paid to the holders of any outstanding class or series of preferred stock. Because we are a holding company, holders of common stock may not receive assets of our subsidiaries in the event of our liquidation until the claims of creditors of such subsidiaries are paid, except to the extent that we are a creditor of, and may have recognized claims against, such subsidiaries.

Voting Rights

Each holder of common stock entitled to vote will have one vote for each one share of common stock held on all matters to be voted upon by our stockholders, including elections of directors.

Except as otherwise required by law, our Certificate of Incorporation or our Bylaws, any question brought before any meeting of stockholders will be decided by the affirmative vote of a majority of the shares present in person or by proxy at the meeting and entitled to vote on the subject matter.

Directors will be elected by a majority of the votes cast, unless the number of nominees exceeds the number of directors to be elected, in which case the directors will be elected by the vote of a plurality of the votes cast.

Conversion, Redemption and Preemptive Rights

Holders of our common stock have no conversion, redemption, preemptive, subscription or similar rights.

Anti-Takeover Effects of our Certificate of Incorporation and Bylaws and of Delaware Law

Our Certificate of Incorporation and our Bylaws and Delaware law contain certain provisions that may have the effect of delaying, deferring or preventing a takeover attempt that a stockholder might consider in its best interest, including those attempts that result in a premium over the market price for the shares held by stockholders. Following is a description of certain of the anti-takeover effects of such provisions.

Special Meetings of Stockholders. Our Certificate of Incorporation and Bylaws currently provide that special meetings of our stockholders may be called by our board of directors or the Chairman of our board of directors. In addition, subject to certain procedural requirements contained in our Certificate of Incorporation and Bylaws, special meetings of stockholders may be called by the Secretary upon the written request of record holders of at least 25% of our outstanding common stock.

Advance Notice Requirements for Stockholder Proposals and Director Nominations. Our Bylaws provide that stockholders seeking to bring business before an annual meeting of stockholders, or to nominate candidates for election as directors at an annual or special meeting of stockholders, must provide timely notice to us thereof in writing within the time periods specified in our Bylaws. Our Bylaws also specify requirements as to the form and content of a stockholder’s notice.

Stockholder Action by Written Consent. Stockholders are permitted to take action without a meeting by written consent, subject to certain procedures specified in our Certificate of Incorporation and Bylaws.

Limitations on Stockholders’ Ability to Change the Number of Directors. The number of directors to serve on our board of directors is fixed by our Bylaws, and, pursuant to our Bylaws, can only be changed by resolution of our board of directors. In addition, our Certificate of Incorporation provides that any vacancy on our board of directors (including any vacancy resulting from an increase in the number of directors) may be filled by a majority of our board of directors then in office.

Authorized but Unissued Capital Stock. Our Certificate of Incorporation authorizes our board of directors to issue one or more series of preferred stock, and to determine, with respect to any such series of preferred stock, the number of shares to be included in any series and the designation, relative powers, preferences, rights and qualifications, limitations or restrictions of such series of preferred stock. The Delaware General Corporation Law (“DGCL”) does not require stockholder approval for any issuance of previously authorized shares of our capital stock. However, the listing requirements of the NYSE, which will apply so long as our common stock is listed on the NYSE, require stockholder approval of certain issuances of common stock or securities convertible into or exercisable for common stock equal to or exceeding 20% of the then outstanding voting power or then outstanding number of shares of our common stock. These additional shares may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions.

No Cumulative Voting. The DGCL provides that stockholders of a Delaware corporation are not entitled to the right to cumulate votes in the election of directors unless its certificate of incorporation provides otherwise. Our Certificate of Incorporation provides that holders of common stock do not have cumulative voting rights in the election of directors or otherwise.

EX-10.1

Exhibit 10.1

Occidental Petroleum Corporation Savings Plan

Amended and Restated
Effective as of January 1, 2019

Active 42603797.7

Contents

Article 1. Introduction     1

1.1 Restatement of Plan 1

1.2 Purpose and Applicability of the Plan1

1.3 Structure of the Plan 1

Article 2. Definitions and Construction2

2.1 Definitions 2

2.2 Gender and Number 23

2.3 Headings 23

2.4 Requirement to Be in “Written Form” 23

2.5 Severability 23

2.6 Applicable Law 23

Article 3. Participation, Service and Vesting23

3.1 Date of Participation 23

3.2 Duration 24

3.3 Transfers 24

3.4 Service 24

3.5 Vesting 25

3.6 Forfeiture of Contingent Interests 27

Article 4. Active Participant Contributions27

4.1 Pre-Tax Deferrals, Roth Contributions and After‑Tax Contributions 27

4.2 Catch‑Up Contributions 28

4.3 Election Procedures 29

4.4 Salary Reduction 30

4.5 Deposit and Crediting of Deferrals and Contributions 30

4.6 Eligible Automatic Enrollment Arrangement 30

Article 5. Employer Contributions32

5.1 Employees Eligible for Matching Contributions 32

5.2 Amount of Matching Contributions 32

5.3 Depositing and Crediting Matching Contributions 33

Article 6. Benefit Limitations33

6.1 Elective Deferral Limit 33

6.2 Discrimination Limits on Pre-Tax Deferrals and Roth Contributions 35

6.3 Corrective Measures if ADP Test Failed 37

6.4 Discrimination Limits on Matching Contributions, After‑Tax Contributions, and Adjustment Contributions 40

6.5 Corrective Measures if ACP Test Failed 42

6.6 Limitation on Annual Additions 45

6.7 Limitation on Pay Taken Into Account 48

6.8 Deductibility Limitation 49

Article 7. Benefit Distributions49

7.1 Distributions Generally 49

7.2 In‑Service Withdrawals 49

7.3 Benefits Upon Separation from Service 52

7.4 Payment Rules 52

7.5 Death Benefits 57

7.6 Required Minimum Distributions 58

7.7 Mandatory Tax Withholding and Direct Rollovers 62

7.8 In-Plan Roth Rollovers 64

7.9 Hurricane Harvey Relief 65

Article 8. Participant Loans66

8.1 Availability of Loans 66

8.2 Amount of Loan 67

8.3 Procedures for Loans 67

Article 9. Investment Elections67

9.1 Investment of Contributions 67

9.2 Transfers of Existing Balances 69

9.3 Transfer of Assets 70

9.4 Reserved 70

9.5 Matching Account Diversification Rights After August 1, 2004 70

Article 10. Participant Accounts and Records of the Plan71

10.1 Accounts and Records 71

10.2 Account Value 71

10.3 Investment Funds 72

10.4 Unit Value of Investment Funds 72

10.5 Calculation of Unit Value 72

10.6 Valuation Adjustments 72

10.7 Debiting of Accounts upon Distribution, Withdrawal, Loan or Charge 72

10.8 Unit Value upon Transfer of Investment Funds 73

10.9 Oxy Stock Fund Valuation 73

10.10 Value of Accounts 74

10.11 Cost Account 74

10.12 Rollover and Roth Rollover Contributions 74

10.13 Merger of the THUMS Long Beach Company Savings and Investment Plan 76

Article 11. Financing76

11.1 Trust Fund 76

11.2 Oxy Stock Fund 77

11.3 Forfeitures 81

11.4 Non‑Reversion 81

11.5 Direct Transfer of Assets from Plans of Acquired Entities 82

11.6 Pension Expense Reimbursement Account (“PERA”) 82

Article 12. Administration82

12.1 The Administrative Committee 82

12.2 Chairperson, Secretary, and Employment of Specialists 83

12.3 Compensation and Expenses 83

12.4 Manner of Action 83

12.5 Subcommittees 84

12.6 Other Agents 84

12.7 Records 84

12.8 Rules 84

12.9 Administrative Committee’s Powers and Duties 84

12.10 Investment Responsibilities 85

12.11 Administrative Committee’s Decisions Conclusive 86

12.12 Indemnity 86

12.13 Fiduciaries 88

12.14 Notice of Address 89

12.15 Data 89

12.16 Benefit Claims Procedures 89

12.17 Member’s Own Participation 92

Article 13. Amendment and Termination92

13.1 Amendment and Termination 92

13.2 Distribution on Termination 93

13.3 Successors 93

13.4 Plan Merger or Transfer 93

Article 14. Participating Affiliates93

14.1 Adoption of the Plan 93

14.2 Conditions of Participation 94

14.3 Termination of Participation 94

14.4 Consequences of the Termination of an Employer 94

Article 15. Top‑Heavy Provisions    96

15.1 Application of Top‑Heavy Provisions 96

15.2 Definitions Applicable to this Article 96

15.3 Determination of Top‑Heavy Ratio 97

15.4 Required Minimum Allocations 98

15.5 Required Minimum Vesting 99

15.6 Employees Covered by Collective Bargaining Agreement 99

Article 16. Miscellaneous Provisions99

16.1 No Enlargement of Employment Rights 99

16.2 No Examination or Accounting 100

16.3 Investment Risk 100

16.4 Non‑Alienation 100

16.5 Incompetency 101

16.6 Records Conclusive 102

16.7 Counterparts 102

16.8 Service of Legal Process 102

16.9 Uncashed or Unclaimed Benefits 102

16.10 Qualified Military Service 103

Article 1. Introduction

1.1 Restatement of Plan

Effective as of January 1, 2019, Occidental Petroleum Corporation (“Company”) hereby amends and restates the Occidental Petroleum Corporation Savings Plan (“Plan”) to make amendments and changes as reflected herein. The provisions of this restatement shall be effective as of January 1, 2019, except as follows or as otherwise specifically provided in this document. Where a particular provision of this restatement has an effective date earlier than January 1, 2019, the relevant provision of this restatement shall supersede the corresponding provision of the prior version of the Plan as of the earlier effective date. Where a particular provision of this restatement has an effective date later than January 1, 2019, the relevant provision of the prior version of the Plan shall continue to apply prior to such effective date.

1.2 Purpose and Applicability of the Plan

This Plan is intended to encourage and assist Eligible Employees in adopting a regular program of savings to provide additional security for their retirement. Except as otherwise provided herein, the provisions of this Plan restatement are applicable only to Eligible Employees on or after January 1, 2019. Unless otherwise explicitly provided in this Plan restatement, the Plan provisions in effect prior to this restatement shall continue to govern the terms and conditions of the Plan prior to January 1, 2019.

Notwithstanding any contrary Plan provision, if any modification of ERISA or the Code (or regulations or rulings thereunder) requires that a conforming Plan amendment be adopted as of a stated effective date in order for the Plan to continue to be a qualified plan, this Plan shall be operated in accordance with such requirements until the date when a conforming Plan amendment is adopted.

1.3 Structure of the Plan

The Plan is intended to qualify as a stock bonus plan under Code section 401(a) that includes a qualified cash or deferred arrangement under Code section 401(k)(2).

Effective June 1, 2002, to enable the deduction on dividends paid on certain employer securities as permitted by Code section 404(k), the Matching Accounts, or portions thereof, invested in the Oxy Stock Fund under the Plan, at any point in time and in the aggregate, are intended to qualify, and are hereby designated, as an employee stock ownership plan (“ESOP”), within the meaning of Code section 4975(e)(7). Effective July 19, 2007, to expand the availability of the deduction on dividends paid on employer securities as permitted by Code section 404(k), the ESOP is expanded to include the Oxy Stock Fund and the portions of Matching Accounts not invested in the Oxy Stock Fund shall cease to constitute part of the ESOP. On or before July 18, 2007, the Matching Accounts, or portions thereof, invested in the Oxy Stock Fund under the Plan, at any point in time, taken together, and effective on or after July 19, 2007, all assets invested in the Oxy Stock Fund at any point in time, regardless of funding source, constitute an “eligible individual account plan,” as defined in ERISA section 407(d)(3), which explicitly provides for the acquisition and holding of and investment primarily in shares of Oxy Stock which constitute “qualifying employer securities,” as described in Code section 4975(e)(8), and “employer securities,” as defined in Code section 409(l).

The Company intends that the Plan and the ESOP together shall constitute a single plan under ERISA and the Code. Accordingly, the provisions set forth in the other sections of the Plan shall apply to the ESOP in the same manner as those provisions apply to the remaining portions of the Plan, except to the extent that those provisions are by their terms inapplicable to the ESOP, or to the extent that they are inconsistent with the specific provisions set forth herein. Except as set forth in specific provisions herein that are related to the ESOP, including but not limited to Plan section 9.5, the designation of any portion of the Plan constituting part of the ESOP shall not affect any Beneficiary designations or any other applicable agreements, elections or consents that Participants, Spouses, Alternate Payees or Beneficiaries validly executed under the terms of the Plan before June 1, 2002, the effective date of the ESOP; and such designations, agreements, elections, and consents shall apply under the ESOP in the same manner as they apply under the Plan.

Article 2. Definitions and Construction

2.1 Definitions

Whenever used in the Plan, the following terms shall have the respective meanings set forth below, unless otherwise expressly provided; and when the defined meaning is intended, the term is capitalized.

(a) “Account” means the separate recordkeeping account maintained for each Participant which represents his or her total proportionate interest in the Trust Fund and which consists of the sum of following:

(1) After‑Tax Account;

(2) After-Tax Rollover Account;

(3) In-Plan Roth Rollover Account;

(4) Matching Account;

(5) Pre-Tax Account;

(6) Rollover Account;

(7) Roth Account; and

(8) Roth Rollover Account.

The term “Account” shall also include any separate account established on behalf of an Alternate Payee pursuant to a Qualified Domestic Relations Order or a Beneficiary following the Participant’s death.

(b) “Accounting Date” means any day on which trading occurs on the New York Stock Exchange.

(c) “ACP Test” means the average contribution percentage test performed in accordance with Plan section 6.4.

(d) “Active Participant” means any Eligible Employee who:

(1) Has met the requirements to become a Participant as set forth in Article 3,

(2) Continues to be employed as an Eligible Employee, and

(3) Has not become an Inactive Participant or Former Participant.

(e) “Actual Deferral Percentage” means, for each group of Participants for any period, the average of the ratios (calculated separately for each Participant in each group) of Pre-Tax Deferrals and/or Roth Contributions taken into account under the rules of this paragraph made on behalf of the Participant for the Plan Year to that Participant’s Testing Compensation earned while a Participant for the Plan Year. Such ratios and the Actual Deferral Percentage for each group shall be calculated to the nearest one‑hundredth of 1 percent of a Participant’s Testing Compensation. If Pre-Tax Deferrals or Roth Contributions cannot be taken into account under the ADP Test because they do not meet the following rules, then such amount must satisfy the nondiscrimination requirements of Code section 401(a)(4) for the Plan Year for which they are made. The following rules shall apply in determining the Average Deferral Percentages:

(1) Pre-Tax Deferrals and Roth Contributions shall be taken into account for the Plan Year in determining a Participant’s Actual Deferral Percentage only if all of the following requirements are met:

(A) The Pre-Tax Deferral and/or Roth Contribution is allocated as of a date in the Plan Year and the allocation is not contingent on the Participant’s participation in the Plan or performance of services for an Employer after the allocation date.

(B) The Pre-Tax Deferral and/or Roth Contribution is contributed to the Trust Fund no more than 12 months after the last day of the Plan Year.

(C) The Pre-Tax Deferral and/or Roth Contribution is made on account of the Participant’s election to reduce Earnings that would otherwise be paid within that Plan Year. Notwithstanding the foregoing, to the extent elected by the Administrative Committee on a uniform basis, Pre-Tax Deferrals and/or Roth Contributions may be taken into account for the Plan Year if they are attributable to services performed during the Plan Year and, but for the Participant’s election to reduce Earnings, would have been received by the Participant after the last day of the Plan Year but within 2½ months after the last day of the Plan Year. If the Administrative Committee makes this election for a Plan Year, then the Pre-Tax Deferrals and/or Roth Contributions shall be taken into account only in the ADP Test (or the ACP Test) for that Plan Year and shall not be taken into account in the ADP Test (or the ACP Test) for any other Plan Year.

(2) If any Highly Compensated Employee is a participant under two or more qualified cash or deferred arrangements of the Company or any Affiliate (including this Plan), all such cash or deferred arrangements shall be treated as one such arrangement for purposes of determining the Actual Deferral Percentage of the Highly Compensated Employee, except as provided in Treasury Regulations section 1.401(k)‑2(a)(3)(ii).

(3) Pre-Tax Deferrals and/or Roth Contributions of Highly Compensated Employees for the Plan Year shall include Excess Deferrals, whether or not such Excess Deferrals are distributed under Plan section 6.1.

(4) Pre-Tax Deferrals and/or Roth Contributions taken into account under the ACP Test of Plan section 6.4 for the Plan Year shall not be taken into account under the ADP Test of this Plan section for the same or any other Plan Year.

(5) Pre-Tax Deferrals and/or Roth Contributions made pursuant to Code section 414(u) shall not be taken into account for purposes of the ADP Test (or the ACP Test) for the Plan Year in which they are made or in any other Plan Year.

(f) “ADP Test” means the actual deferral percentage test performed in accordance with Plan section 6.2.

(g) “Adjustment Contributions” means Pre-Tax Deferrals and/or Roth Contributions which are recharacterized as After‑Tax Contributions in order to comply with nondiscrimination tests of Code sections 401(k) and 401(m), as described in Plan sections 6.2 and 6.4. To the extent required by Treasury Regulations section 1.401(m)‑2(b)(3), Adjustment Contributions after recharacterization shall be treated as:

(1) After‑Tax Contributions for purposes of Code sections 72, 401(a)(4), and 401(m); and

(2) Pre-Tax Deferrals and/or Roth Contributions for purposes of Code sections 401(a) (other than Code sections 401(a)(4), 401(k), and 401(m)), 404, 409, 411, 415, 416, and 417.

(h) “Administrative Committee” means the committee appointed by the Board to administer the Plan in accordance with the applicable provisions of Article 12 of this Plan.

(i) “Affiliate” means:

(1) Any business entity while it is controlled by or under common control with the Company within the meaning of Code sections 414 and 1563, or

(2) Any member of an affiliated service group, within the meaning of Code section 414(m), of which the Company or any Affiliate is a member; and

(3) Any entity which, pursuant to Code section 414(o) and related Treasury Regulations, must be aggregated with the Company or any Affiliate for plan qualification purposes.

For purposes of paragraph (1), the determination of control shall be made without reference to paragraphs (a)(4) and (e)(3)(C) of Code section 1563. For the purposes of applying the limitations of Plan sections 2.1(nnn) and 6.6, the phrase “more than 50 percent” shall be substituted for the phrase “at least 80 percent” each place it appears in Code section 1563(a)(1).

(j) “After‑Tax Account” means the recordkeeping account which evidences the value of After‑Tax Contributions and any Adjustment Contributions, including related investment gains and losses of the Trust Fund.

(k) “After‑Tax Contributions” means the voluntary contributions made by a Participant to the Plan on an after‑tax basis, as described in Plan section 4.1.

(l) “After-Tax Rollover Account” means the recordkeeping account which evidences the value of After-Tax Rollover Contributions, including related investment gains and losses of the Trust Fund.

(m) “After-Tax Rollover Contributions” means the eligible after-tax contributions made at the direction of the Employee pursuant to Plan section 10.12 on or after January 1, 2020.

(n) “Alternate Payee” means, with respect to a Participant, any Spouse, former Spouse, child, or other dependent of that Participant, who is an alternate payee, within the meaning of Code section 414(p)(8), and who is recognized by a Qualified Domestic Relations Order as having the right to receive all or a portion of the benefits payable under the Plan with respect to the Participant.

(o) “Annual Addition” means the sum of the amounts described in Plan section 6.6(b).

(p) “Annual Bonus” means up to the first $100,000 of bonus paid from an Employer to an Active Participant, who is not a “named executive officer,” as that term is defined in Regulations S‑K under the Securities Exchange Act of 1934 (17 CFR §229.402(a)(3)), during the Plan Year under a regular annual incentive compensation plan, such as the Company’s Variable Compensation Program or Incentive Compensation Program (but excluding without limitation a special individual or group bonus, a project bonus, and any other special bonus).

(q) “Average Contribution Percentage” means, for each group of Participants for any period, the average of the ratios (calculated separately for each Participant in each group) of the sum of Matching Contributions, After‑Tax Contributions, and Adjustment Contributions made on behalf of the Participant for the Plan Year to that Participant’s Testing Compensation earned while a Participant for the Plan Year. Such ratios and Average Contribution Percentage for each group shall be calculated to the nearest one‑hundredth of 1 percent of an Eligible Employee’s Testing Compensation. If Matching Contributions, After‑Tax Contributions or Adjustment Contributions cannot be taken into account under the ACP Test because they do not meet the following rules, then such amount must satisfy the nondiscrimination requirements of Code section 401(a)(4) for the Plan Year for which they are made. The following rules shall apply in determining the Average Contribution Percentages:

(1) After‑Tax Contributions shall be taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year that the After‑Tax Contributions are transferred to the Trust Fund. For this purpose, an After‑Tax Contribution is treated as transferred to the Trust Fund at the time it would have been paid to the Participant if it is transferred to the Trust Fund within a reasonable time after the amount is withheld from the Participant’s Earnings.

(2) Adjustment Contributions are taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year in which the Adjustment Contributions are includible in the gross income of the Participant.

(3) Matching Contributions are taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year only if all of the following are met:

(A) The Matching Contribution is made on account of the Participant’s Pre-Tax Deferrals, Roth Contributions or After‑Tax Contributions for the Plan Year.

(B) The Matching Contribution is allocated to the Participant’s Matching Account as of a date within the Plan Year.

(C) The Matching Contribution is transferred to the Trust Fund no more than 12 months after the last day of the Plan Year.

(4) Any Matching Contributions that are forfeited because the Pre-Tax Deferrals, Roth Contributions or After‑Tax Contributions to which they relate are determined to be an Excess Deferral, an Excess Contribution, or an Excess Aggregate Contribution for the Plan Year are not taken into account in determining a Participant’s Average Contribution Percentage for the Plan Year.

(5) If any Highly Compensated Employee is a participant under two or more Qualified Plans of the Company or any Affiliate (including this Plan) that provide for matching contributions or after‑tax contributions, all such contributions made by or on behalf of the Highly Compensated Employee under such Qualified Plans during the 12‑

(6) Matching Contributions and After‑Tax Contributions made pursuant to Code section 414(u) shall not be taken into account for purposes of the ACP Test for the Plan Year in which they are made or in any other Plan Year.

(7) Subject to the conditions prescribed and to the extent permitted by Treasury Regulations section 1.401(m)‑2(a)(6)(ii), the Administrative Committee may elect to take into account Pre-Tax Deferrals and Roth Contributions in computing Average Contribution Percentages.

(r) “Base Pay” means the base salary and wages earned by an Active Participant from an Employer for services rendered, including amounts of Pre-Tax Deferrals, Roth Contributions and amounts contributed pursuant to the Pre-Tax Spending Program.

(1) Base Pay does not include:

(A) Bonuses, incentives, overtime, shift differential, and overseas differentials;

(B) Reimbursement for expenses or allowances, including automobile allowances and moving allowances;

(C) Any amount contributed by the Employer (other than Pre-Tax Deferrals, Roth Contributions and amounts contributed pursuant to the Pre-Tax Spending Program) to any pension plan or plan of deferred compensation;

(D) Any amount contributed by an Employer (in addition to Pre-Tax Deferrals, Roth Contributions and Catch‑Up Contributions) to this Plan;

(E) Any amount paid by an Employer for other fringe benefits, such as health and hospitalization, and group life insurance benefits, or perquisites; and

(F) Allowances paid during furlough and, for purposes of paragraph (2)(F) below, such furloughs shall not be treated as paid leaves of absence.

(2) Base Pay is determined in accordance with the following rules:

(A) For Active Participants compensated by salary, Base Pay means the actual base salary of record paid to the Active Participant (subject to the exclusions listed above).

(B) For Active Participants compensated based on mileage driven (primarily truck drivers), Base Pay means the number of miles driven multiplied by the applicable mileage pay rate (subject to the exclusions listed above), plus the Active Participant’s scheduled number of hours worked in the pay period multiplied by the Active Participant’s base hourly rate (subject to the exclusions listed above).

(C) For Active Participants compensated at an hourly rate, Base Pay means the base hourly rate (subject to the exclusions listed above) multiplied by the number of regularly scheduled hours worked in a pay period. If the Active Participant’s regularly scheduled work week is more than 40 hours, Base Pay shall include an additional amount equal to the base hourly rate (subject to the exclusions listed above) times one half the number of regularly scheduled hours worked in excess of 40 in the work week.

(D) For Active Participants compensated on an eight, ten, twelve, or some other assigned hour Shift Basis and whose annual Base Pay is pre‑determined under the Company’s payroll recordkeeping, Base Pay for each pay period shall be the Active Participant’s pre-determined annual Base Pay (subject to the exclusions listed above) divided by the number of pay periods applicable to the Active Participant during the Plan Year. For the purpose of this subsection, the term “Shift Basis” means any arrangement whereby Active Participants work the assigned hour daily shifts which may result in alternating work weeks of more and less than 40 hours per week.

(E) Base Pay includes paid time off and vacation pay received in periodic payments and annual paid time off and vacation payments made to Employees paid by commission, but does not include single sum paid time off and vacation payments to active or terminating Employees.

(F) Base Pay includes base salary or wages received during paid leaves of absence and periodic notice pay, but, effective July 1, 2006, Base Pay does not include single sum notice pay payments or any severance pay payments.

(G) Base Pay does not include long‑term disability payments or payments made to any Participant pursuant to the Occidental Chemical Corporation Weekly Sickness and Accident Plan unless:

(i) Such payments are made to the Participant through the payroll accounting department of the Company or an Affiliate, and

(ii) The Participant is ineligible for participation in the Retirement Plan.

(H) Base Pay includes any payment to a Participant who does not currently perform services for an Employer by reason of qualified military service (within the meaning of Code section 414(u)(1)) to the extent that the payment does not exceed the amount that the Participant would have received if the Participant continued to perform services for the Employer rather than entering qualified military service.

(s) “Beneficiary” means the person or persons (who may be named contingently or successively) designated by a Participant, an Alternate Payee, or a Beneficiary of a deceased Participant or a deceased Alternate Payee to receive his or her Account in the event of death.

If no Beneficiary is designated at the time of the Participant’s or Alternate Payee’s death, or at the time of death of the Beneficiary of a deceased Participant or Alternate Payee, or if no person so designated shall survive the Participant, Alternate Payee, or Beneficiary of a deceased Participant or Alternate Payee, the Beneficiary shall be the deceased person’s Spouse, or if the deceased individual has no surviving Spouse, his or her surviving children equally, or if there are no surviving children, his or her surviving parents equally, or if only one parent is living, his or her living parent, or if no parent is living, his or her surviving siblings equally, or if only one sibling is living, his or her surviving sibling, or if no sibling is living, his or her estate.

The designation by a married Participant of someone other than the Participant’s Spouse as a Beneficiary shall be invalid unless:

(1) The Spouse consents in writing to the designation of any specific non‑Spouse Beneficiary which may not be changed without the Spouse’s consent (unless the Spouse’s consent expressly permits the Participant to change Beneficiary designations without further consent by the Spouse);

(2) The consent acknowledges the effect of such designation; and

(3) The consent is notarized.

No spousal consent shall be required if it is established to the satisfaction of the Plan representative that such consent cannot be obtained because there is no Spouse or because the Spouse cannot be located.

Notwithstanding the foregoing, where an Employee becomes a Participant through merger of his or her account from another plan into this Plan, “Beneficiary” means the person or persons so designated under such other plan until a new Beneficiary designation is effected as described above by such Employee.

(t) “Board” means the Board of Directors of the Company.

(u) “Catch‑Up Contributions” means the contributions made by the Employer, on or after June 30, 2002, on behalf of an Active Participant, who will have attained age 50 before the last day of the Plan Year, on a Pre-Tax and/or Roth basis as elected by the Participant pursuant to Plan section 4.2. Catch‑Up Contributions for the Plan Year may not exceed the limit in effect for such Plan Year under Code section 414(v)(2)(B)(i), as adjusted pursuant to Code section 414(v)(2)(C).

(v) “Code” means the Internal Revenue Code of 1986, as amended. Each Code reference in this Plan shall be deemed to include reference to any comparable or succeeding statutory provision which supplements or replaces such Code reference.

(w) “Company” means Occidental Petroleum Corporation.

(x) “Covered Employee” means a Participant who is covered under the Plan’s eligible automatic contribution arrangement under Section 4.6. Prior to October 8, 2019, a Covered Employee will include all Eligible Employees hired on or after August 5, 2016, excluding interns and temporary employees, and on and after October 8, 2019, a Covered Employee will include all Eligible Employees (including Eligible Employees hired prior to August 5, 2016).

(y) “Disability” means the disability of:

(1) Any Active Participant who is determined to be disabled under section 423 of Title 42 of the U. S. Code and who receives disability insurance benefits thereunder; or

(2) Any Active Participant who is a participant in the Occidental Petroleum Corporation Long‑Term Disability Plan or, prior to March 1, 2002, the OxyVinyls, LP Long‑Term Disability Plan and who is determined to be disabled therein under the definition of “disability” applicable to the period beginning 24 months after the commencement of disability and who receives benefits thereunder.

An Active Participant shall be considered to have incurred the Disability as of the time of the commencement of the disability benefits as described above while the Active Participant was an Employee.

A Former Participant shall be considered to have incurred the Disability and retroactively vest upon receipt of more than 18 months of benefits under the Occidental Petroleum Corporation Long-Term Disability Plan.

A Participant who claims to have incurred the Disability as a result of being determined to be disabled under section 423 of Title 42 of the U.S. Code must give written notice thereof to the Administrative Committee and submit, at the expense of the Participant, to the Administrative Committee such evidence of Disability as the Administrative Committee may require. Failure by a Participant to comply with the foregoing requirements shall be deemed conclusive evidence that such Participant has not incurred the asserted Disability. All rules with respect to the determination of Disability shall be uniformly and consistently applied to all Participants in similar circumstances.

(z) “Earnings” means the sum of Base Pay and Annual Bonus paid to an Active Participant by an Employer during the Plan Year. Effective for Plan Years beginning after 2001, the annual Earnings of each Participant taken into account in determining allocations for any Plan Year shall not exceed $200,000, as adjusted for cost‑of‑living increases in accordance with Code section 401(a)(17)(B).

(aa) “Eligible Dividends” means, as further described in Plan section 11.2:

(1) Between June 1, 2002 and July 18, 2007, dividends paid on Oxy Stock held in the Oxy Stock Fund attributable to the Participant’s Matching Account constituting the ESOP portion of the Plan; and

(2) On or after July 19, 2007, dividends paid on Oxy Stock held in the Oxy Stock Fund constituting the ESOP portion of the Plan.

(3) Eligible Dividends paid on Oxy Stock held in the Oxy Stock Fund attributable the Participant’s Matching Account shall be reflected in the Participant’s Matching Account. Eligible Dividends paid on Oxy Stock held in the Oxy Stock Fund attributable to other than the Participant’s Matching Account shall be reflected for recordkeeping purposes in the After-Tax Account, Pre-Tax Account, Rollover Account, Roth Account or Roth Rollover Account from which the Eligible Dividend is derived.

(bb) “Eligible Employee” means any Employee who is employed by an Employer, unless excluded under one or more of the following categories of Employees:

(1) Represented Employees where retirement benefits were the subject of good faith bargaining between the Employer and the union, unless the collective bargaining agreement covering the Represented Employees expressly provides participation in the Plan. Represented Employees covered by collective bargaining agreements providing for their participation in the Plan became Eligible Employees as of the dates noted in Appendix A.

(2) Employees who are nonresident aliens who receive no earned income from the Employer which constitutes U.S.‑source income under Code section 861(a)(3), unless the Administrative Committee expressly makes the Plan available to such an Employee.

(3) Leased Employees.

(4) Employees of Occidental Oil and Gas Corporation who immediately before January 1, 2008 were eligible employees under the THUMS Long Beach Company Savings and Investment Plan (as defined in that plan) and who thus continue to participate under that plan. Notwithstanding the previous sentence, effective July 1, 2008, Employees of Occidental Oil and Gas Corporation who immediately before July 1, 2008 were eligible employees under the THUMS Long Beach Company Savings and Investment Plan (as defined in that plan) shall be Eligible Employees under this Plan.

(5) Effective August 8, 2019, any Employee of Anadarko Petroleum Corporation who is not a citizen or legal resident of the United States and is not regularly employed at a worksite of Employer within the United States.

(cc) “Employee” means any person employed by the Company or an Affiliate.

Notwithstanding any other provision of this subsection, no individual shall be an Employee if such individual is not classified as a common‑law employee in the employment records of the Company or an Affiliate, without regard to whether the individual is subsequently determined to have been a common‑law employee of the Company or an Affiliate. The persons excluded by this paragraph from being Employees are to be interpreted broadly to include and to have at all times included individuals engaged by the Company or an Affiliate to perform services for such entity in a relationship that the entity characterizes as other than an employment relationship, such as where the Company or the Affiliate engages the individual to perform services as an independent contractor or leases the individual’s services from a third party. The exclusion of the individual from being an Employee shall apply even if a determination is subsequently made by the Internal Revenue Service, another governmental agency, a court or other tribunal, after the individual is engaged to perform such services, that the individual is an Employee of the Company or Affiliate for purposes of pertinent Code sections or for any other purpose.

(dd) “Employer” means the Company and any Affiliate which is designated, in accordance Article 14, by the Board or, if authorized by the Board, the Administrative Committee and which adopts the Plan. Affiliates which are not corporations are not eligible to be Employers under the Plan.

(ee) “ESOP” means, as further described in Plan section 1.3:

(1) Between June 1, 2002 and July 18, 2007, the portion of the Plan comprised of the Matching Accounts, or portions thereof, invested in the Oxy Stock Fund under the Plan, at any point in time and in the aggregate, and

(2) On or after July 19, 2007, the Oxy Stock Fund, at any point in time and in the aggregate.

(ff) “Excess Aggregate Contribution” means the amount contributed by or on behalf of a Highly Compensated Employee in excess of the ACP Test limit, as specified in Plan section 6.5.

(gg) “Excess Contribution” means the amount deferred by a Highly Compensated Employee in excess of the ADP Test limit, as specified in Plan section 6.3.

(hh) “Excess Deferral” means the amount deferred by a Participant on a Pre-Tax or Roth basis in excess of the dollar limit specified in Plan section 6.1.

(ii) “ERISA” means the Employee Retirement Income Security Act of 1974, as from time to time amended. Each ERISA reference in this Plan shall be deemed to include reference to any comparable or succeeding statutory provision which supplements or replaces such ERISA reference.

(jj) “Former Participant” means an Active Participant or Inactive Participant who has had a Separation from Service, but whose Account has not been fully distributed.

(kk) “Highly Compensated Employee” means an Employee described in Code section 414(q) and includes any Employee who:

(1) Was a 5-percent owner (as defined in Code section 416(i)(1)(B)(i)) at any time during the Plan Year or the preceding Plan Year; or

(2) For the preceding Plan Year, received Section 415 Compensation in excess of $80,000 (as adjusted by reference to Code section 414(q)(1)).

Employees who are nonresident aliens and who receive no U.S.‑source income shall not be counted as Employees when identifying Highly Compensated Employees. In determining Highly Compensated Employees, the Administrative Committee may make any of the elections permitted under Code section 414(q), IRS Notice 97‑45 and any future guidance provided by the Internal Revenue Service.

A Former Participant shall be treated as a former Highly Compensated Employee if the Participant was a Highly Compensated Employee in a separation year, as defined in Treasury Regulations section 1.414(q)–1T, Q&A 5, or after the date on which the participant attained age 55.

(ll) “Inactive Participant” means an Employee who was an active Participant but who is transferred to and is in a position of employment where he is no longer an Eligible Employee, as described in Plan section 3.3(b).

(mm) “In-Plan Roth Rollover Account” means the recordkeeping account which evidences the value of In-Plan Roth Rollover Contributions, including gains and losses of the Trust Fund.

(nn) “In-Plan Roth Rollover Contributions” means the eligible contributions made at the direction of the Employee in accordance with Code section 402A(c)(4) and Plan section 7.8.

(oo) “Investment Committee” means the committee appointed by the Board to administer the investments of the Plan.

(pp) “Investment Fund” means funds that have been approved by the Investment Committee for investment in the Trust Fund and includes the Oxy Stock Fund. The Investment Committee may, from time to time in its discretion and in exercise of its fiduciary responsibilities, select different funds, add to the set of available funds, close funds to new investment, or remove one or more funds (except the Oxy Stock Fund). The current set of Investment Funds shall be maintained and documented in Appendix B.

(qq) “Leased Employee” means any person within the meaning of Code section 414(n)(2) who is not reported on the payroll records of the Company or any Affiliate as a common law employee and who provides services to the Company or an Affiliate, but only if the services are provided under an agreement between the Company or Affiliate and a leasing organization, the person has performed services for the Company and Affiliates on a substantially full time basis for a period of at least one year, and the services are performed under the primary direction or control of the Company or Affiliate that is the service recipient.

Contributions or benefits provided to a Leased Employee by the leasing organization which are attributable to services performed for the Company and Affiliates will be treated as provided by the Company or Affiliate. If a Leased Employee subsequently becomes an Eligible Employee, Service as a Leased Employee will be credited under the Plan to the extent required by Code section 414(n).

Notwithstanding the foregoing, an individual will not be a Leased Employee for a Plan Year for nondiscrimination testing or for any other purpose, if either paragraph (1) or (2) is applicable to that individual for that Plan Year.

(1) The individual is covered by a money purchase pension plan meeting the requirements of Code section 414(n)(5)(B) and Leased Employees, determined without regard to the limitation in this paragraph, do not constitute more than 20% of all Nonhighly Compensated Employees of the Company and all Affiliates.

(2) All requirements of this paragraph are satisfied for that Plan Year and each previous Plan Year with respect to which Code section 414(n) was effective with respect to the Company or any Affiliate.

(A) The Qualified Plans of the Company and all Affiliates exclude Leased Employees from participation and no such Qualified Plan is top-heavy (within the meaning of Code section 416);

(B) The number of leased persons, providing services to the Company and all Affiliates during the Plan Year, is less than 5% of the number of Employees (excluding such leased persons and Highly Compensated Employees) covered by any Qualified Plan maintained by the Company or any Affiliate at any time during such Plan Year. An individual is a leased person for this purpose if all of the following requirements are satisfied:

(i) During the Plan Year, the individual performs any services for the Company or any Affiliate, other than as an Employee, and the requirements of Code section 414(n)(2)(A) (relating to performing services pursuant to an agreement with the Company or any Affiliate) and Code section 414(n)(2)(C) (relating to performing services under the primary direction or control of the Company or any Affiliate) are satisfied.

(ii) During the Plan Year, the individual is credited with at least 1,500 hours of service, including service performed as an Employee and in any other capacity. For purposes of this subparagraph, “hours of service” has the same meaning as the term “hour of service” provided by Department of Labor Regulations section 2530.200b‑2. If one of the equivalencies set forth in Department of Labor Regulations section 2530.200b‑3 is used, such equivalency shall be used on a reasonable and consistent basis and the 1,500‑hour requirement must be adjusted accordingly. With respect to determining whether an individual has satisfied the 1,500‑hour requirement, reasonable approximations may be made.

(iii) The individual either:

(I) Is not covered under a Qualified Plan as an Employee at any time during the Plan Year; or

(II) Performs at least 501 hours of service (reasonably adjusted if one of the equivalencies set forth in Department of Labor Regulations section 2530.200b–3 is used) for the Company or any Affiliate other than as an Employee.

(C) The Administrative Committee has not been notified by the leased person and provided satisfactory evidence by the leased person that he or she is a Leased Employee.

(rr) “Nonhighly Compensated Employee” means an Employee who is not a Highly Compensated Employee.

(ss) “Nonrepresented Employees” means any Employee who is not a Represented Employee.

(tt) “Matching Account” means the recordkeeping account which evidences the value of Matching Contributions and the value of Eligible Dividends paid on Oxy Stock held in the Participant’s Matching Account, including related investment gains and losses of the Trust Fund.

(uu) “Matching Contributions” means the contributions made by the Employer pursuant to Plan section 5.2 on account of Pre-Tax Deferrals, Roth Contributions or After‑Tax Contributions made on behalf of or by the Participant.

(vv) “MidCon Corp. ESOP” means the MidCon Corp. Employee Stock Ownership Plan as effective November 20, 1996.

(ww) “Oxy Stock” means the common stock of Occidental Petroleum Corporation, which is the class of stock having the greatest voting power and dividend rights. Oxy Stock is readily tradable on established securities market within the meaning of Treasury Regulation section 1.401(a)(35)-1(f)(5) for purposes of Code sections 401(a)(22), 401(a)(28)(C), 409(h)(1)(B), 409(l) and 1042(c)(1)(A).

(xx) “Oxy Stock Fund” means the Investment Fund that is invested primarily in Oxy Stock and such short‑term interest‑bearing securities as the Investment Committee or the Trustee considers advisable.

(yy) “Participant” means an Active Participant, Inactive Participant, or a Former Participant, as applicable.

(zz) “Plan Year” means the calendar year.

([[) “Pre-Tax Account” means the recordkeeping account which evidences the value of Pre-Tax Deferrals, including related investment gains and losses of the Trust Fund.

(aaa) “Pre-Tax Deferrals” means the contributions made by the Employer on behalf of the Participant on a Pre-Tax basis as elected by the Participant pursuant to Plan section 4.1.

(bbb) “Pre-Tax Spending Program” means the Occidental Petroleum Corporation Flexible Spending Accounts Plan.

(ccc) “Qualified Domestic Relations Order” means a qualified domestic relations order, within the meaning of Code section 414(p), which creates or recognizes the existence of an Alternate Payee’s right to, or assigns to an Alternate Payee the right to, receive all or a portion of the benefits payable to a Participant.

(ddd) “Qualified Plan” means a plan, other than this Plan, which is qualified under Code section 401(a).

(eee) “Represented Employee” means any Employee, whose employment is subject to a collective bargaining agreement.

(fff) “Retirement Plan” means the Occidental Petroleum Corporation Retirement Plan.

(ggg) “Rollover Account” means the recordkeeping account which evidences the value of Rollover Contributions, including related investment gains and losses of the Trust Fund.

(hhh) “Rollover Contributions” means the eligible pre-tax contributions made at the direction of the Employee pursuant to Plan section 10.12.

(iii) “Roth Account” means the recordkeeping account which evidences the value of Roth Contributions, including related investment gains and losses of the Trust Fund, but excluding any forfeitures.

(jjj) “Roth Contributions” means the contributions made by the Employer on behalf of the Participant on an after-tax basis as elected by the Participant pursuant to Plan section 4.1. A Participant’s Roth Contributions will be separately accounted for, as will gains and losses attributable thereto, in a separate account. Roth Contributions are not considered After-Tax Contributions for Plan purposes.

(kkk) “Roth Rollover Account” means the recordkeeping account which evidences the value of Roth Rollover Contributions, including related investment gains and losses of the Trust Fund.

(lll) “Roth Rollover Contributions” means an eligible rollover contribution of any payment or distribution from another Roth rollover account of the Employee. A Participant’s Roth Rollover Contributions will be maintained in a separate account which includes any earnings properly allocable to such contributions and that will have separate recordkeeping.

(mmm) “Separation from Service” means any termination of the employment relationship between an Employee and the Company and all Affiliates. A Separation from Service shall be deemed to occur upon the earlier of:

(1) The date upon which the Employee quits, is discharged, is laid off, incurs a Disability, or dies; or

(2) The first anniversary of the first day of a period in which the Employee is (and remains) absent from the Service for any reason (such as paid time off, vacation, sickness, or approved leave of absence) not enumerated in paragraph (1), provided that if an Employee is granted a leave of absence but fails to return to employment at the end of the leave period, Separation from Service will be deemed to have occurred upon the date the Employee was originally granted a leave of absence.

(3) Notwithstanding paragraph (2), the Separation from Service date of an Employee who is absent from Service beyond the first anniversary of the first day of absence by reason of a maternity or paternity leave is the second anniversary of the first day of such absence. The period between the first and second anniversaries of the first day of absence from work is neither a period of Service nor a period of severance. For purposes of this paragraph, an absence from work for maternity or paternity reasons means an absence:

(A) By reason of the pregnancy of the individual;

(B) By reason of the birth of a child of the individual;

(C) By reason of the placement of a child with the individual in connection with the adoption of such child by such individual; or

(D) For purposes of caring for such child for a period beginning immediately following such birth or placement.

Effective for distributions after December 31, 2001, a transaction constituting a severance of employment, within the meaning of Code section 401(k)(2)(B)(i)(I), with respect to an Employee shall also be deemed to be a Separation from Service.

An Employee of an Employer who transfers to an Affiliate that is not an Employer shall not be treated as having a Separation from Service. Moreover, an Employee’s date of quit or discharge shall not be deemed to occur until any periodic notice payments, short‑term disability payments, or weekly sickness and accident payments cease.

An Employee who is on leave of absence in order to serve the Armed Forces of the United States shall not have a Separation from Service unless the Employee fails to report for work at the end of such leave and prior to expiration of the period in which the Employee has reemployment rights under law. The absence of any Employee who fails to return to work within the allotted time shall be subject to the provisions of paragraph (2).

(nnn) “Service” means the periods of employment credited using the elapsed time method described to an Employee under Plan section 3.4.

(ooo) “Section 415 Compensation” means, with respect to a Participant for the period specified, the total cash and non‑cash remuneration paid to a Participant by the Employer or an Affiliate, determined as follows:

(1) Section 415 Compensation includes all amounts described in Treasury Regulations section 1.415–2(d)(2), including:

(A) All wages; bonuses; other amounts received (without regard to whether the amount is paid in cash) for personal services actually rendered in the course of employment with the Company or any Affiliate, to the extent that the amounts are includible in gross income for federal income tax purposes and for which the Company or Affiliate is required to furnish to the Participant a written statement under Code sections 6041(d), 6051(a)(3), and 6052;

(B) Amounts paid or reimbursed by the Company or Affiliate for moving expenses incurred by the Participant, but only to the extent that at the time of the payment it is reasonable to believe that these amounts are not deductible by the Participant under Code section 217; and

(C) The value of a nonqualified stock option granted to the Participant by the Company or Affiliate, but only to the extent that the value of the option is includible in the gross income of the Participant, for federal income tax purposes, for the taxable year in which granted.

(2) In addition, Section 415 Compensation includes all of the following:

(A) The Participant’s Pre-Tax Deferrals, Roth Contributions and Catch‑Up Contributions for the Plan Year;

(B) Elective contributions that are excluded from the Participant’s gross income under a Code section 125 cafeteria plan maintained by the Participant’s Employer, such as the Pre-Tax Spending Program; and

(C) Any elective deferral, as defined in Code section 402(g)(3), made under a plan maintained by the Company or any Affiliate, and any amount which is contributed to or deferred by the Company or any Affiliate at the election of the Participant and which is not includible in the gross income of the Participant by reason of Code sections 125, 132(f)(4), 408(k), or 457.

(D) Effective July 1, 2006, Section 415 Compensation includes remuneration paid by the later of 2½ months after an Employee’s Separation from Service or the end of the Plan Year that includes the date of the Employee’s Separation from Service with the Company or an Affiliate, if:

(i) The payment is regular compensation for services during the Employee’s regular working hours, or compensation for services outside the employee’s regular working hours (such as overtime or shift differential), commissions, bonuses, or other similar payments, and, absent a Separation from Service, the payments would have been paid to the Employee while the Employee continued in employment with the Company or an Affiliate;

(ii) The payment is for unused accrued bona fide sick, paid time off, vacation or other leave that the Employee would have been able to use if there had not been a Separation from Service;

(iii) The payment is to an individual who does not currently perform services for the Company or any Affiliate by reason of qualified military service (within the meaning of Code section 414(u)(1)) to the extent the payment does not exceed the amount the individual would have received if the individual had continued to perform services for the Company or an Affiliate rather than entering qualified military service; or

(iv) Compensation paid to a Participant who is permanently and totally disabled (as defined in Code section 22(e)(3)), provided that salary continuation applies to all Participants who are permanently and totally disabled for a fixed or determinable period.

Any payment not described above shall not be considered Section 415 Compensation if paid after a Separation from Service, even if paid by the later of 2½ months after the Separation from Service or the end of the Plan Year that includes the Separation from Service. Back pay shall be treated as Section 415 Compensation for the Plan Year to which the back pay relates to the extent the back pay represents wages and compensation that would otherwise be included under this definition.

(3) However, Section 415 Compensation excludes all amounts described in Treasury Regulations section 1.415–2(d)(3), including the following amounts:

(A) Any contributions made by the Company or any Affiliate to a plan of deferred compensation to the extent that, before the application of the limitations of Code section 415 to that plan, the contributions are not includible in the gross income of the employee for the taxable year in which contributed;

(B) Distributions from a plan of deferred compensation, regardless of whether such amounts are includible in the gross income of the employee when distributed; provided, however, that distributions from and any amounts received by the Participant pursuant to an unfunded nonqualified plan are included in Section 415 Compensation in the year the amounts are includible in the gross income of the Participant;

(C) Amounts realized from the exercise of a nonqualified stock option, or when restricted stock or property held by the Participant either becomes freely transferable or is no longer subject to a substantial risk of forfeiture;

(D) Amounts realized from the exercise of an incentive stock option, as defined in Code section 422, or the sale, exchange, or other disposition (including a disqualifying disposition) of stock acquired through the exercise of an incentive stock option;

(E) Amounts realized from the sale, exchange, or other disposition of stock acquired under an employee stock purchase plan, as defined in Code section 423; and

(F) Other amounts which receive special tax benefits, such as premiums for group‑term life insurance, but only to the extent that the premiums are not includible in the gross income of the employee for federal income tax purposes.

(ppp) “Supplemental Plan Participant” means a Participant in this Plan who is or was also a participant in the Occidental Petroleum Corporation Supplemental Retirement Plan, effective through December 31, 2004, or the Occidental Petroleum Corporation Supplemental Retirement Plan II, effective as of January 1, 2005, as determined under Appendix G to this Plan.

(qqq) “Spouse”means the individual of the opposite sex and, effective as of June 26, 2013, also includes an individual of the same sex, to whom a Participant is married, where the marriage was valid at the time the marriage ceremony was performed, in a state or foreign jurisdiction (the “Jurisdiction”) having legal authority to sanction such marriage, provided that such marriage has not subsequently been legally dissolved. For purposes of the Plan, such a marriage shall be treated as valid even if the couple is domiciled in a Jurisdiction that does not recognize the validity of the marriage. Notwithstanding the foregoing, for the period beginning June 26, 2013 and ending September 15, 2013, the Plan may be administered to recognize only those marriages between members of the same sex where the couple was domiciled in a Jurisdiction where the validity of the marriage was recognized during such period. For purposes of the Plan, the term “marriage” does not include a registered domestic partnership, civil union or other similar formal relationship recognized under the laws of a Jurisdiction but which is not recognized as a marriage under that Jurisdiction, even if state law provides that persons in these relationships have the same rights, protections, and benefits, under state law, as married persons.

(rrr) “Testing Compensation” means, for purposes of the ADP Test and ACP Test, compensation within the meaning of Code section 414(s)(1), except that the Administrative Committee may elect not to include in such compensation any amount which is contributed by the Employer pursuant to a salary reduction agreement and which is not includible in gross income of the Employee under Code section 125, 132(f)(4), 402(e)(3), 402(h), or 403(b).

(sss) “Total Excess Aggregate Contributions” means the total amount of Excess Aggregate Contributions to be corrected to satisfy the ACP Test for the Plan Year as determined under Plan section 6.5(b).

(ttt) “Total Excess Contributions” means the total amount of Excess Contributions to be corrected to satisfy the ADP Test for the Plan Year as determined under Plan section 6.3(b).

(uuu) “Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury under the Code.

(vvv) “Trust Agreement” means any agreement in the nature of a trust established to form a part of the Plan to receive, hold, invest, and dispose of the Trust Fund.

(www) “Trust Fund” means the assets of every kind and description held under any Trust Agreement forming a part of the Plan.

(xxx) “Trustee” means any person selected by the Company to act as Trustee under any Trust Agreement at any time of reference.

(yyy) “Unit” means the unit of measure into which each Investment Fund is divided for purposes of ascertaining the share of each such fund attributable to each Participant, Beneficiary and Alternate Payee.

2.2 Gender and Number

Except as otherwise indicated by the context, any masculine or feminine terminology shall also include the opposite gender, and the definition of any term in the singular or plural shall also include the opposite number.

2.3 Headings

The headings of this Plan are inserted for convenience or reference only, and they are not to be used in the construction of the Plan.

2.4 Requirement to Be in “Written Form”

Various notices provided by the Company, the Administrative Committee, or the Investment Committee and various elections made by a Participant, Spouses, Alternate Payees and Beneficiaries are required to be in written form. Notwithstanding anything to the contrary in this Plan, any notices and elections related to the Plan may be conveyed through an electronic system or any other system approved by the Administrative Committee unless otherwise provided under applicable law or regulatory guidance. Any such notices, forms, and elections provided or made through an electronic medium shall comply with the provisions of Treasury Regulations section 1.401(a)-21.

2.5 Severability

If a provision of this Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included in the Plan.

2.6 Applicable Law

To the extent not preempted by ERISA or other federal law, the Plan and all rights hereunder shall be governed, construed, and administered in accordance with the laws of the State of Texas with the exception that any Trust Agreement shall be construed and enforced in all respects under and by the laws of the state in which the Trustee thereunder is located.

Article 3. Participation, Service and Vesting

3.1 Date of Participation

Each Eligible Employee shall become an Active Participant as of the first day of the month in which the Employee becomes an Eligible Employee. Notwithstanding the foregoing, each Employee who becomes an Eligible Employee pursuant to a purchase or other agreement approved by the Board shall become an Active Participant as of the date, if any, specified in such agreement. A Covered Employee will be notified that he or she is eligible to participate in the Plan at the time he or she becomes an Eligible Employee. If the Covered Employee does not make an affirmative election not to participate in the Plan or return an alternative election pursuant to section 4.1 of the Plan, then Pre-Tax Deferrals will automatically begin to be made on such Covered Employee’s behalf as described in section 4.6 of the Plan.

3.2 Duration

An Eligible Employee who becomes an Active Participant shall remain an Active Participant for as long as he remains an Eligible Employee or is entitled to receive any contributions or benefits hereunder.

3.3 Transfers

(a) Transfers to Eligible Employee Status. An Employee who transfers to employment as an Eligible Employee shall become an Active Participant on the first day of the month in which such transfer takes place.

(b) Transfers from Eligible Employee Status. A Participant who transfers to employment status where he or she no longer is an Eligible Employee shall become an Inactive Participant.

(1) An Inactive Participant is not eligible to make or receive Pre-Tax Deferrals, Roth Contributions, Catch‑Up Contributions, After‑Tax Contributions (including Adjustment Contributions) or Matching Contribution on Earnings paid after the date of transfer to an ineligible status.

(2) An Inactive Participant shall continue to accrue Service under this Plan. Upon Separation from Service, the Participant’s vested interest shall be based on total Service with the Company and all Affiliates.

(3) An Inactive Participant remains eligible to receive in‑service withdrawals, subject to the terms of Plan section 7.2, plan loans, subject to the terms of Article 8, and to transfer eligible amounts to his or her Rollover Account, Roth Rollover Account or After-Tax Rollover Account, subject to the terms of Plan section 10.12.

3.4 Service

Service is used to determine a Participant’s vested percentage in his or her Matching Account.

(a) General Rules. An Employee shall be credited with Service on an elapsed time basis for the period during which the employment relationship exists between the Employee and the Company or any Affiliate, the length of which shall be determined, in completed years and months, during the following periods of time:

(1) Credit shall be given to an Employee for the period of time beginning on the first day of the month in which the individual first becomes an Employee and ending on the last day of the month in which occurs the Employee’s Separation from Service.

(2) Credit shall be given to an Employee for each period beginning upon the date the individual has a Separation from Service and ending upon the first day of the month in which the individual first becomes an Employee thereafter but only if the Employee is reemployed within 12 months of the date of such Separation from Service.

(3) Credit shall be given to an Employee after a Separation from Service for any period beginning on the first day of the month in which the Employee first becomes an Employee after rehire and ending on the last day of the month the Employee has a Separation from Service thereafter.

(4) Whenever the total number of years of Service of an Employee must be ascertained under this Plan, all noncontinuous periods of Service which are credited to such Employee shall be aggregated, regardless of the length or any period of Service and regardless of the length of any period between a Separation from Service and rehire. For purposes of aggregating such years of Service, the completed years and months credited to an Employee during any period of Service shall be added to the number of completed years and months credited to the Employee during any other period of noncontinuous Service. This Plan does not disregard periods of Service, even though permitted to do so under Code section 411(a)(6).

(5) Service by any Leased Employee shall be credited under this section should the Leased Employee ever become an Eligible Employee under this Plan.

(b) Special Rules. For purposes of determining an Employee’s Service under this Plan, the special Service counting rules set forth in Appendix C shall apply to increase, but not decrease, the Service of any Employee.

3.5 Vesting

(a) Employee Accounts. A Participant’s interest in his or her Pre-Tax Account, Roth Account, After‑Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account shall be fully vested at all times.

(b) Matching Account. A Participant’s interest in his or her Matching Account shall become vested in accordance with this section, if not vested earlier under the special vesting rules of subsection (c).

(1) Unless vested earlier under the provisions of this section, a Participant shall vest in his or her Matching Account based on the Participant’s completed years of Service.

(A) Effective January 1, 2007, a Participant who is first employed by a Company or any Affiliate after 2006, shall have no nonforfeitable right to his or her Matching Account until the Participant completes three years of Service and shall be 100 percent vested in his or her Matching Account when the Participant is credited with three or more years of Service.

(B) Effective January 1, 2007, a Participant who was first employed by the Company or any Affiliate before 2007, shall have the nonforfeitable percentage of his Matching Account determined based on the following table:

Years of Service	Percentage Vested
Less than 1	0	%
1	20	%
2	40	%
3	100	%

(C) Effective January 1, 2015, an Active Participant, irrespective of when he or she was first employed by the Company or an Affiliate, shall be 100 percent vested in his or her Matching Account.

(2) Furthermore, a Participant shall become fully vested in his or her Matching Account to the extent required under Code section 411(d)(3) and Plan section 13.2 upon a complete termination of the Plan, a partial termination of the Plan affecting the Participant, or upon a complete discontinuance of contributions to the Plan.

(c) Special Vesting Rules.

(1) Notwithstanding the foregoing, a Participant described in Appendix D shall vest in his or her Matching Account under the provisions of that Appendix D, rather than subsection (b).

(2) A Participant shall at all times be fully vested in any Eligible Dividends with respect to which the Participant is offered a dividend pass‑through deduction to the extent required under Plan section 11.2(d)(3). These amounts will be held in either:

(A) The Participant’s Matching Account, or

(B) The Participant’s Pre-Tax Account, Roth Account, After-Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account, in which the Participant is always fully vested, based on the account from which the Eligible Dividend is derived.

(3) With respect to any frozen contributions under this Plan or any Qualified Plan that is merged into this Plan, if such contributions resume under this Plan or any Qualified Plan into which this Plan is merged, then for purposes of determining the Participant’s nonforfeitable right to such contributions, a Participant shall receive credit for Service incurred both prior to and subsequent to the date such contributions were frozen.

(d) Vesting and Benefit Payments. Being vested does not mean that a Participant is entitled to immediate distribution benefits. Benefits under the Plan shall be paid only in accordance with Article 7.

3.6 Forfeiture of Contingent Interests

Any portion of a Participant’s Account that is not vested under the provisions of Plan section 3.5 shall be forfeited upon the first to occur of the following forfeitable events:

(a) The Participant elects, in accordance with Plan section 7.3, to commence or receive a distribution of the value of the Participant’s vested Account on account of a Separation from Service. For this purpose, if the percentage vested in the table under Plan section 3.5(b)) is zero, the Participant will be deemed to have elected such a distribution and the nonvested portion of the Account will be immediately forfeited.

(b) The Participant incurs five consecutive breaks in service. For this purpose, a break in service is a period of 12 months in which the Participant is absent from Service, except that if the absence is due to a maternity or paternity reason described in Plan section 2.1(lll)(3), the period between the first and second anniversaries of such absence shall be neither a period of Service nor a period of severance.

If the Participant who has forfeited his nonvested Account resumes employment as an Eligible Employee, then the cash value (determined at the time of forfeiture) of the amount forfeited shall be restored to the Participant’s Account. No buyback shall be required and the reinstatement will occur regardless of the length of the Participant’s absence from Service.

Article 4. Active Participant Contributions

4.1 Pre-Tax Deferrals, Roth Contributions and After‑Tax Contributions

(a) Covered Employees will be automatically enrolled in the Plan as described in Plan section 4.6 below.

(b) Except as otherwise provided in this Plan, each Active Participant may elect to contribute as After‑Tax Contributions or to have the Employer contribute on the Participant’s behalf as Pre-Tax Deferrals and Roth Contributions an amount of the Participant’s Base Pay which together is from 1 percent to the contribution percentage limit specified for the Active Participant in Appendix E for the Plan Year. The Administrative Committee may adjust the contribution percentage limit specified in Appendix E at the beginning of each Plan Year without the need of a formal Plan amendment, provided that any such limitations shall be communicated to eligible Participants in advance of the pay periods to which such limitations will apply. The percentage elected of Pre-Tax Deferrals, Roth Contributions and/or After‑Tax Contributions may be in increments of a tenth of a percent.

The Participant’s elected Pre-Tax Deferral, Roth Contribution and After-Tax Contribution percentages shall apply, but not in excess of an aggregate of 5 percent, to the Active Participant’s Annual Bonus. The Annual Bonus shall be counted for this purpose in the Plan Year it is paid even if it is received for services performed in a prior Plan Year. Effective January 1, 2017, unless the Participant affirmatively elects otherwise, with respect to any Participant hired prior to August 5, 2016, the election in effect as of August 5, 2016 will apply to any Annual Bonus paid in the 2017 Plan Year and any subsequent plan year until the Participant affirmatively elects otherwise.

(c) Notwithstanding anything in this Plan to the contrary, no Participant shall be permitted to have elective deferrals made under this Plan, or any other Qualified Plan maintained by the Company or Affiliates during any taxable year, in excess of the dollar limitation contained in Code section 402(g)(1) in effect for such taxable year, except to the extent permitted under Code section 414(v).

(d) No benefits other than Matching Contributions shall be conditioned on a Participant’s election to make After‑Tax Contributions or have Pre-Tax Deferrals and Roth Contributions made on the Participant’s behalf under this Plan. Any portion of a contribution that is not designated as a Pre-Tax Deferral, Roth Contribution or Catch‑Up Contribution shall be designated as an After‑Tax Contribution.

(e) The Participant’s election made under this section shall be made in accordance with the rules set forth in this Article and such other rules of nondiscriminatory application as the Administrative Committee may prescribe for the proper administration of the Plan.

4.2 Catch‑Up Contributions

Each Active Participant who will have attained age 50 before the close of the Plan Year shall be eligible to make Catch‑Up Contributions in accordance with and subject to the limitations of Code section 414(v) for pay periods ending after July 1, 2002. Each Participant must elect whether such Catch-Up Contributions will be in the form of Pre-Tax Deferrals or Roth Contributions.

(a) Catch‑Up Contributions shall not be taken into account for purposes of the provisions of Plan sections 6.1 and 6.6, implementing the required limitations of Code sections 402(g) and 415, respectively.

(b) The Plan shall not be treated as failing to satisfy the provisions of the Plan sections 6.2, 6.4, or Article 15, implementing the requirements of Code section 401(k)(3), 401(k)(11), 401(k)(12), 410(b), or 416, as applicable, by reason of the making of Catch‑Up Contributions.

(c) Elections to make Catch‑Up Contributions shall be made separately from the Active Participant’s election of Pre-Tax Deferrals or Roth Contributions under Plan section 4.1, shall not be subject to the contribution percentage limit on Pre-Tax Deferrals and Roth Contributions specified in Plan section 4.1, and shall be made in accordance with uniform procedures established by the Administrative Committee. Such election procedures will require the eligible Active Participant to elect Catch‑Up Contributions as a fixed dollar amount per pay period.

(d) Under no circumstances will Catch‑Up Contributions elected under this Plan section entitle the Participant to Matching Contribution, even if it is later determined that the contribution is not a Catch‑Up Contribution because it is less than an applicable limit.

(e) For purposes of recordkeeping and communications with Participants, Catch‑Up Contributions, Pre-Tax Deferrals and Roth Contributions may be aggregated and reported as held in the Participant’s Pre-Tax Account or Roth Account, as applicable, without changing the character of any Catch‑Up Contributions as such for purposes of Code section 414(v).

4.3 Election Procedures

(a) Each Active Participant shall be permitted to make the elections described in Plan section 4.1 and, if eligible, Plan section 4.2 in the manner prescribed by the Administrative Committee. If a Participant has elected to begin, stop, increase, or decrease Pre-Tax Deferrals, Roth Contributions, After‑Tax Contributions or, if eligible, Catch‑Up Contributions, the Active Participant may file a new election in the manner prescribed by the Administrative Committee to change Pre-Tax Deferrals, Roth Contributions, After‑Tax Contributions or, if eligible, Catch‑Up Contributions at any time and such election shall become effective on the first pay period following the date on which the election is properly received. The election shall remain in effect until changed by the Active Participant or until he or she ceases to be an Active Participant or goes on an unpaid leave of absence.

(b) If an Active Participant becomes an Inactive Participant or Former Participant, or goes on unpaid leave of absence, any Pre-Tax Deferrals, Roth Contributions, After‑Tax Contributions and Catch‑Up Contributions for the Participant shall cease. If the individual again becomes an Active Participant or returns from an unpaid leave of absence, he or she may make a new election under this section.

(c) All elections shall apply to Earnings paid in the first available payroll period following the date the election is processed and shall be irrevocable for such period. In addition, except for occasional, bona fide administrative considerations, Pre-Tax Deferrals, Roth Contributions and Catch‑Up Contributions made pursuant to such elections cannot precede the earlier of the performance of services relating to the Pre-Tax Deferrals, Roth Contributions or Catch‑Up Contributions and the date when the Earnings subject to the election would be currently available to the Participant in the absence of an election to defer.

4.4 Salary Reduction

Each Active Participant who makes a Pre-Tax Deferral or Roth Contribution election described in Plan section 4.1 or, if eligible, a Catch‑Up Contribution election described in Plan section 4.2 shall, by the act of making such election or elections, have his or her Earnings reduced by an equivalent amount for so long as the election remains in effect.

4.5 Deposit and Crediting of Deferrals and Contributions

Pre-Tax Deferrals, Roth Contributions, After‑Tax Contributions, and Catch‑Up Contributions shall be transferred to the Trust Fund as soon as reasonably practicable after the payroll payment date at which a corresponding amount would have been paid to the Participant in the absence of the election of such contributions. Pre-Tax Deferrals shall be allocated to the Participant’s Pre-Tax Account; Roth Contributions shall be allocated to the Participant’s Roth Account; Catch‑Up Contributions shall be allocated to the Participant’s Pre-Tax Account and/or Roth Account, as applicable, and After‑Tax Contributions shall be allocated to the Participant’s After‑Tax Contribution Account as of the payroll payment date on which the corresponding amount would have been paid in absence of the elections under Plan section 4.1 and, if applicable, Plan section 4.2, but shall share in any investment gains and losses only after they are received by the Trust Fund.

4.6 Eligible Automatic Enrollment Arrangement

(a) Effective Date. The following automatic enrollment procedures will apply with respect to all Covered Employees. All Covered Employees hired prior to October 8, 2019, who have not made an affirmative election under Plan section 4.1 to make deferrals or contributions to the Plan equal or greater than the Default Percentage (defined below) will be automatically enrolled in accordance with the following automatic enrollment procedures on November 15, 2019. For Plan Years beginning after December 31, 2019, the procedures set forth in this Plan section 4.6 are intended to constitute an eligible automatic contribution arrangement that satisfies Code section 414(w) and provides excise tax relief with respect to excess amounts distributed within 6 months after the end of the plan year under Code section 4979(f).

(b) Default Percentage. A Covered Employee will have a reasonable opportunity after receipt of the automatic enrollment notice to make an alternate election. If a Covered Employee fails to make an alternate election, Pre-Tax Deferrals will automatically begin being made on such Covered Employee’s behalf, in an amount equal to 5% of his or her Base Pay (i.e., the “Default Percentage”) on the Covered Employee’s date of hire.

(c) Alternate Election. In the event a Covered Employee does not desire to have Pre-Tax Deferrals made on his or her behalf at the Default Percentage, the Covered Employee may elect a different amount up to the contribution percentage limit specified for the Active Participant in Appendix E for the Plan Year or elect to not participate in the Plan. Any alternate election is to be made in accordance with the election procedures set forth in Section 4.3 above.

(d) Withdrawal. No later than 30 days after default Pre-Tax Deferrals are first withheld from a Covered Employee’s Base Pay, the Covered Employee may request a distribution of his or her default Pre-Tax Deferrals. The amount to be distributed from the Plan upon the Covered Employee’s request is equal to the amount of default Pre-Tax Deferrals made through the earlier of (a) the pay date for the second payroll period that begins after the Covered Employee’s withdrawal request and (b) the first pay date that occurs 30 days after the Eligible Employee’s request, plus attributable earnings through the date of distribution. Unless the Covered Employee affirmatively elects otherwise, any withdrawal request will be treated as an affirmative election to cease default Pre-Tax Deferrals made on the Covered Employee’s behalf. Default Pre-Tax Deferrals distributed pursuant to this Section 4.6(d) are not counted towards the Code section 402(g) limit. Matching Contributions that might otherwise be allocated to a Covered Employee’s Account on behalf of default Pre-Tax Deferrals will not be allocated to the extent the Covered Employee withdraws such default Pre-Tax Deferrals pursuant to this Section 4.6(d) and any Matching Contributions already made on account of such default Pre-Tax Deferrals that are later withdrawn pursuant to this Section 4.6(d) will be forfeited and subject to allocation as a forfeiture.

(e) Notices. For Plan Years beginning after December 31, 2019, the Company will provide Covered Employees with the notice required under Code section 414(w)(4) describing the Plan’s automatic enrollment procedures prior to the beginning of each Plan Year regardless of whether the Covered Employee has an affirmative election for Pre-Tax Deferrals in place.

Article 5. Employer Contributions

5.1 Employees Eligible for Matching Contributions

Subject to the other provisions of this Plan, the Employer shall contribute Matching Contributions to this Plan only for a Participant who was an Active Participant during the pay period for which the corresponding Pre-Tax Deferrals and/or Roth Contributions (including amounts recharacterized as Adjustment Contributions) or After‑Tax Contributions were made. Notwithstanding any Plan provision to the contrary, any Matching Contribution (including any investment gain attributable thereto), which relates to an Excess Deferral under Plan section 6.1, Excess Contribution under Plan section 6.3 (unless recharacterized as Adjustment Contributions) or Excess Aggregate Contribution under Plan section 6.5 shall be forfeited and shall not be treated as a Matching Contribution with respect to the Participant for the Plan Year.

5.2 Amount of Matching Contributions

Matching Contributions shall be made on behalf of an Active Participant for each payroll period for which Pre-Tax Deferrals, Roth Contributions or After-Tax Contributions were made with respect to the Participant for the Plan Year. Matching Contributions may also be made on behalf of eligible Participants, as the Employer or Administrative Committee deems necessary or appropriate for administrative purposes, at such other times, but not later than 12 months after the end of the Plan Year. The amount of Matching Contributions allocated to the Participant’s Matching Contributions Account shall be equal to the matching percent shown in the table in Appendix F, based on the employment classification of the Participant on the last day of the payroll period, multiplied by the Pre-Tax Deferrals (including an Adjustment Contribution), Roth Contribution (including an Adjustment Contribution) or After-Tax Contribution made with respect to the Participant on the Participant’s first 5 percent of Base Pay and Annual Bonus for the pay period. With respect to United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, Local 12773 represented employees, the amount of Matching Contributions allocated to the Participant’s Matching Contributions Account shall be equal to the matching percent shown in the table in Appendix F, based on the employment classification of the Participant on the last day of the payroll period, multiplied by the Pre-Tax Deferrals (including an Adjustment Contribution), Roth Contributions (including an Adjustment Contribution) or After-Tax Contribution made with respect to the Participant on the Participant’s first 4 percent of Base Pay and Annual Bonus for the pay period. Effective February 29, 2016, the Matching Contributions allocated with respect to United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, Local 12773 represented employees will be the same as for other Active Participants. Effective January 1, 2016, the Matching Contributions allocated with respect to United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, Local 2154-03 represented employees will be the same as for other Active Participants. The Administrative Committee may limit the amount of Matching Contributions made on behalf of a Participant to the extent that the Administrative Committee determines necessary to comply with the limits of Article 6.

5.3 Depositing and Crediting Matching Contributions

The Company shall make such contributions to the Trust Fund as are required by this Plan, subject to the right of the Company to discontinue the Plan. The Company shall contribute an amount which, when added to forfeitures under Plan section 11.3, is sufficient to provide the Matching Contribution allocations required by Plan section 5.2.

Matching Contributions shall be transferred to the Trust Fund as soon as reasonably practicable after the payroll payment date at which the corresponding Pre-Tax Deferrals, Roth Contributions or After‑Tax Contributions would have been paid to the Participant in the absence of the election of such contributions. Matching Contributions shall be allocated to the Participant’s Matching Account as of the payroll payment date on which the corresponding amount would have been paid in absence of the Participant’s election, but shall share in any investment gains and losses only after they are received by the Trust Fund.

Article 6. Benefit Limitations

6.1 Elective Deferral Limit

(a) Dollar Limit. For any calendar year, the sum of the following items shall not exceed the elective deferral dollar limit of Code section 402(g)(1), as adjusted pursuant to Code section 402(g)(4):

(1) All Pre-Tax Deferrals and Roth Contributions (but not Catch‑Up Contributions) made on behalf of an Active Participant for that calendar year; and

(2) Any other Pre-Tax or Roth contributions made for the calendar year to any Qualified Plan maintained by the Company or any Affiliate which are elective deferrals as defined in Code section 402(g)(3), but not including any such elective deferrals that are catch‑up contributions under Code section 414(v).

Any amount deferred in excess of the dollar limit stated in this subsection is referred to as an Excess Deferral.

(b) Calendar Year as Participant’s Taxable Year. A Pre-Tax Deferral and Roth Contribution made on behalf of an Active Participant shall be treated as made for a calendar year, for purposes of Plan section 6.1(a)(1) if it is made on account of the Active Participant’s election to reduce Earnings that would otherwise be payable within that calendar year.

(c) Preventing Excess Deferrals. If before the end of a calendar year, the Administrative Committee determines (or the Active Participant notifies his or her Employer that he or she has determined) that Pre-Tax Deferrals and/or Roth Contributions to be made on behalf of an Active Participant for that calendar year would exceed the limits of this section or Code section 402(g), then the Administrative Committee shall take one or both of the following steps, to the extent necessary, to avoid exceeding the limits of this section or Code section 402(g):

(1) Permit an Active Participant to submit a revised election under Plan section 4.1; or

(2) Reduce Pre-Tax Deferrals and/or Roth Contributions that otherwise would be made, pursuant to the Participant’s current election, for the rest of the calendar year (and adjust the corresponding reductions in Earnings) so that the limits are not exceeded.

(d) Correcting Excess Deferrals. If Excess Deferrals have been made on the Participant’s behalf in excess of the limits of Code section 402(g), then the Excess Deferrals shall be corrected as follows:

(1) The Participant must notify the Administrative Committee, by such other means as the Administrative Committee shall prescribe, no later than March 1, immediately following the close of a calendar year, stating that the sum of the items described in subsection 6.1(a) are in excess of the limits of Code section 402(g). The notice provided by the Participant shall state the portion of such excess amount that has been allocated to this Plan as an Excess Deferral. The amount of the Excess Deferral allocated to this Plan shall not exceed the total amount of the Pre-Tax Deferrals and/or Roth Contributions (excluding Catch‑Up Contributions) made on behalf of the Participant for that calendar year. The Administrative Committee may require the Participant to certify to the amount of the Excess Deferral and to provide substantiating evidence satisfactory to the Administrative Committee.

(2) If the Active Participant does not provide the notice described in paragraph (1) by the following March 1, but it is determined that Pre-Tax Deferrals and/or Roth Contributions (excluding Catch‑Up Contributions) made on behalf of an Active Participant for a calendar year inadvertently exceed the limits of subsection (a), then the Excess Deferral for the calendar year shall be distributed in accordance with this subsection.

(3) The Administrative Committee shall direct the Trustee to distribute, by April 15 following the close of the calendar year, the Excess Deferral for that calendar year allocated (or deemed allocated) to the Plan by the Participant. Any Excess Deferrals shall be treated as consisting first of any Pre-Tax Deferrals made by the Participant for such Plan Year, as applicable, and second any Roth Contributions which the Participant made for the Plan Year, as applicable, except as otherwise elected by the Participant. The distributed Excess Deferral shall be withdrawn from the Investment Funds in which the Pre-Tax Account and/or Roth Account, as applicable, is then invested on a pro rata basis. The Trustee shall also distribute the net income attributable to the Excess Deferrals, as determined by the Administrative Committee in accordance with one of the methods permitted under Treasury Regulations section 1.402(g)–1(e)(5) disregarding, effective January 1, 2007, any provision of prior regulations relating to the distribution of gap period earnings. Corrective distributions under this subsection shall be coordinated with distributions of Excess Contributions under Plan section 6.3 in accordance with Treasury Regulations sections 1.401(k)–1(f)(5) and 1.402(g)–1(e)(6). Any Matching Contributions that have been made with respect to Excess Deferrals that are distributed to a Highly Compensated Employee, in accordance with this subsection, shall be forfeited, as soon as is practicable after corrective distributions are made. Such Matching Contributions shall be forfeited, whether or not the Participant would otherwise have a vested interest in those Matching Contributions, pursuant to Plan section 3.5.

6.2 Discrimination Limits on Pre-Tax Deferrals and Roth Contributions

As of the last day of each Plan Year, the Administrative Committee shall require testing of Pre-Tax Deferrals and Roth Contributions made for the Plan Year to assure that the Actual Deferral Percentage (ADP) for the Plan Year of Participants who are Highly Compensated Employees does not exceed the ADP Test limits specified in this Plan section.

(a) Aggregation, Disaggregation and Restructuring. The rules of this section shall be administered so as to comply with the mandatory disaggregation requirements of Treasury Regulations section 1.410(b)‑7(c) and, if the Administrative Committee chooses, the permissive aggregation rules of Treasury Regulations section 1.410(b)‑7(d), provided that any aggregated plans shall use the same testing method under Treasury Regulations section 1.401(k)‑2(a)(2)(ii) (i.e., current year or prior year testing method) as is used by the Plan for the Plan Year. Notwithstanding the foregoing, effective January 1, 2004, the mandatory disaggregation rules relating to the ESOP and non‑ESOP portions of the Plan shall not apply.

(1) To the extent required by the mandatory disaggregation rules, Represented Employees and Nonrepresented Employees shall be treated as comprising separate plans for purposes of applying the ADP Test. Notwithstanding the foregoing, the Administrative Committee may treat two or more separate collective bargaining units as a single collective bargaining unit for purposes of applying the ADP Test, provided that the combinations of units are determined on a basis that is reasonable and reasonably consistent from Plan Year to Plan Year.

(2) If, after application of the mandatory disaggregation rules, this Plan is permissively aggregated with one or more other plans that include qualified cash or deferred arrangements for purposes of Code section 401(a)(4) or 410(b), then the cash or deferred arrangements of this Plan and such other plans shall be treated as one arrangement for purposes of this Plan section.

(3) In determining whether the restrictions of this Plan section are met, the Administrative Committee may exclude from the ADP Test all Eligible Employees who are not Highly Compensated Employees and who have not met the minimum age and service requirements of Code section 410(a)(1)(A), if the Administrative Committee elects to apply Code section 410(b)(4)(B). Alternatively, the Administrative Committee may apply the ADP Test separately to all Eligible Employees who have not met the minimum age and service requirements of Code section 410(a)(1)(A).

(b) ADP Test. The Actual Deferral Percentage for the Plan Year of Participants who are Highly Compensated Employees shall not exceed the greater of:

(1) The product of 1.25 and the Actual Deferral Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year; or

(2) The lesser of:

(A) The product of two and the Actual Deferral Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year, or

(B) The Actual Deferral Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year plus two percentage points.

By an amendment to the Plan, the Administrative Committee may elect to apply paragraphs (1) and (2) by using the Actual Deferral Percentage of Employees who are not Highly Compensated Employees for the prior Plan Year only if the current year testing method has been used for at least the last five Plan Years. If the Plan is aggregated with any other Qualified Plan, the Actual Deferral Percentage of Employees who are not Highly Compensated Employees for the prior Plan Year may be used only if the Plan is amended to so provide and each Qualified Plan that is aggregated with this Plan used the current year method for at least the last five years (or, if shorter, the period that such other Qualified Plan was in existence, including years in which the Qualified Plan was a portion of another Qualified Plan).

(c) The restrictions of this section shall be based on the Participant’s actual Testing Compensation while an Active Participant and total Pre-Tax Deferrals and Roth Contributions allocated to the Participant’s Account for the Plan Year. The Administrative Committee is authorized to restrict the Pre-Tax Deferrals and Roth Contributions of Highly Compensated Employees in a uniform manner if it determines, based on advance testing done during the Plan Year, that such restriction is necessary or appropriate to assure final Plan Year compliance with restrictions of this section.

6.3 Corrective Measures if ADP Test Failed

If, at the end of the Plan Year, the Administrative Committee determines that the Actual Deferral Percentage of Highly Compensated Employees exceeds the maximum permitted for the Plan Year under the ADP Test, then the Administrative Committee shall take the corrective steps described in this Plan section so that the requirements of Plan section 6.2 are met for the Plan Year. Pre-Tax Deferrals and Roth Contributions, along with any other elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly Compensated Employee, exceeding the ADP Test limits are referred to as Excess Contributions.

(a) Correction Methods. To the extent permitted under Treasury Regulations section 1.401(k)‑2(b)(3) and this Plan section, the Administrative Committee shall first recharacterize Excess Contributions, along with allocable investment gains and losses, as Adjustment Contributions. To the extent Excess Contributions remain for the Plan Year, the Administrative Committee shall next distribute the Excess Contributions, along with allocable investment gains and losses, pursuant to Treasury Regulations section 1.401(k)‑2(b)(2) and this Plan section. Regardless of whether recharacterized or distributed, all corrections of Excess Contributions shall be made in accordance with Treasury Regulations section 1.401(k)‑2(b)(4) and this Plan section.

(b) Determining Total Excess Contributions.The amount of Excess Contributions attributable to each Highly Compensated Employees is the amount by which Pre-Tax Deferrals and Roth Contributions, along with any other elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly Compensated Employee, must be reduced so that the Actual Deferral Percentage for that Highly Compensated Employee is reduced to the maximum permissible Actual Deferral Percentage for Highly Compensated Employees. The maximum permissible Actual Deferral Percentage for Highly Compensated Employees is determined by reducing the Actual Deferral Percentage for the Highly Compensated Employee with the highest Actual Deferral Percentage for the Plan Year to the Actual Deferral Percentage for the Highly Compensated Employee with the next highest Actual Deferral Percentage. If a lesser reduction would enable the ADP Test to be satisfied, only the lesser reduction is used to determine the maximum permissible Actual Deferral Percentage. This procedure is repeated until the ADP Test would be satisfied. The total amount of Excess Contributions to be corrected is equal to the sum of the dollar amounts computed under this subsection for each Highly Compensated Employee and is to be referred to as the Total Excess Contributions.

(c) Apportionment of Total Excess Contributions. Total Excess Contributions for the Plan Year shall be apportioned among Highly Compensated Employees as provided in this subsection.

(1) Pre-Tax Deferrals and/or Roth Contributions allocated to the Highly Compensated Employee with the highest dollar amount of Pre-Tax Deferrals and/or Roth Contributions taken into account under the ADP Test for the Plan Year, including any other elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly Compensated Employee, shall be reduced by the amount required to cause that Highly Compensated Employee’s remaining amount of Pre-Tax Deferrals and/or Roth Contributions for the Plan Year to be equal to the dollar amount of Pre-Tax Deferrals and/or Roth Contributions for the Highly Compensated Employee with the next highest dollar amount. This amount shall be allocated as the Excess Contribution for the Highly Compensated Employee, unless a smaller reduction, when added to the total dollar amount already allocated as Excess Contributions for other Highly Compensated Employees pursuant to this procedure equals the Total Excess Contributions for the Plan Year. Excess Contributions shall be treated as consisting first of any Pre-Tax Deferrals made by the Participant for such Plan Year, as applicable, and second any Roth Contributions which the Participant made for the Plan Year, as applicable, except as otherwise elected by the Participant.

(2) If a Highly Compensated Employee’s Excess Contributions include elective deferrals made to other qualified cash or deferred arrangements that are included in the Actual Deferral Percentage of a Highly Compensated Employee, then the Excess Contribution of that to the Highly Compensated Employee shall not exceed the Pre-Tax Deferrals and/or Roth Contributions made under this Plan for the Plan Year. Any portion of the Total Excess Contributions which is apportioned to a Highly Compensated Employee pursuant to this subsection, but which cannot be corrected because of the preceding sentence, shall be apportioned to the Highly Compensated Employee with the next lowest total dollar amount of Pre-Tax Deferrals and/or Roth Contributions and that Highly Compensated Employee’s Excess Contributions shall be reduced by an amount which includes the amount not corrected for the other Highly Compensated Employee.

(3) If the total amount corrected under this subsection is less than the Total Excess Contributions for the Plan Year, the procedure in this paragraph shall be repeated until the total amount corrected is equal to the Total Excess Contributions for the Plan Year.

(4) The investment gains and losses allocable to the Excess Contributions are equal to the sum of allocable investment gains and losses for the Plan Year and allocable gains and losses after the Plan Year for which the distribution is made. The allocable investment gain or loss attributable to the Excess Contributions may be determined in accordance with any of the methods permitted under Treasury Regulations section 1.401(k)‑2(b)(2)(iv), disregarding any provisions relating to the distribution of gap period earnings, and may be determined up to seven days before the date of the correction.

(5) Excess Contributions of the Highly Compensated Employee with respect to which Matching Contributions were not made shall be corrected to the extent necessary under this Plan section before Excess Contributions of that Highly Compensated Employee with respect to which Matching Contributions were made.

(6) The requirements of this Plan section shall be deemed to have been satisfied if the total dollar amount corrected equals the Total Excess Contributions with allocable investment gains and losses, even if:

(A) The ADP Test would not satisfy the requirements of Plan section 6.2, if the test were rerun including in the test only Pre-Tax Deferrals and/or Roth Contributions that were not corrected under this subsection; or

(B) The amount corrected with respect to each Highly Compensated Employee is different from the amount computed for purposes of calculating the Total Excess Contributions amount.

(d) Rules Applicable to Adjustment Contributions. Excess Contributions shall not be treated as corrected even if recharacterized under this subsection (d), unless the requirements of this subsection are met.

(1) Excess Contributions that are recharacterized as Adjustment Contributions must be reported to the Internal Revenue Service and the Highly Compensated Employee as included in gross income of the Highly Compensated Employees to the same extent they would have been included in gross income if distributed.

(2) Excess Contributions must be recharacterized as Adjustment Contributions no later than 2½ months after the close of the Plan Year (for Plan Years beginning after December 31, 2019, 6 months after the close of the Plan Year). For this purpose, recharacterization will be deemed to have occurred on the date on which the last Highly Compensated Employee is notified that his or her Pre-Tax Deferrals and/or Roth Contributions are being recharacterized as Adjustment Contributions.

(3) Excess Contributions may be recharacterized as Adjustment Contributions for a Plan Year only if the Plan allows After‑Tax Contributions for that Plan Year and such Adjustment Contributions are included in the ACP Test for the Plan Year.

(4) Investment gains and losses allocable to Excess Contributions shall be allocated to the corresponding Adjustment Contributions after recharacterization.

(e) Rules Applicable to Distributions. Excess Contributions shall not be treated as corrected even if distributed under this subsection (e), unless the requirements of this subsection are met.

(1) Excess Contributions and allocable investment gains and losses must be distributed to the Highly Compensated Employee to whom it has been allocated within 12 months after the close of the Plan Year for which the Excess Contribution arose.

(2) The distributed Excess Contributions and allocable investment gains and losses shall be taken from the Investment Funds in which the Pre-Tax Account and/or Roth Account is then invested on a pro rata basis.

(3) Any Matching Contributions that have been made with respect to Excess Contributions that are distributed to a Highly Compensated Employee shall be forfeited, as soon as is practicable after corrective distributions are made. Such Matching Contributions shall be forfeited, whether or not the Participant would otherwise have a vested interest in those Matching Contributions, pursuant to Plan section 3.5.

(4) If the Highly Compensated Employee received a full distribution of his or her Account before Excess Contributions and allocable investment gains and losses are distributed to the Highly Compensated Employee, then the prior distribution shall be reported for taxation purposes as first a correction of Excess Contributions and allocable investment gains and losses to the extent required under this Plan section.

(5) A distribution of Excess Contributions and allocable investment gains and losses shall in no event be treated as satisfying a required minimum distribution for purposes of Code section 401(a)(9) and Plan section 7.6.

(6) The distribution required by this Plan section may be made notwithstanding any other Plan provision.

6.4 Discrimination Limits on Matching Contributions, After‑Tax Contributions, and Adjustment Contributions

As of the last day of each Plan Year, the Administrative Committee shall require testing of Matching Contributions, After‑Tax Contributions, and Adjustment Contributions made for the Plan Year for Participants, who were not Represented Employees for the period for which the contributions were made, to assure that the Average Contribution Percentage for the Plan Year of such Participants who are Highly Compensated Employees does not exceed the limits specified in the ACP Test. The rules of this section shall not apply at all to Matching Contributions, After‑Tax Contributions, and Adjustment Contributions made for the Plan Year for Participants who are Represented Employees for the period for which the contributions are made.

(a) Aggregation, Disaggregation and Restructuring. The rules of this section shall be administered so as to comply with the mandatory disaggregation requirements of Treasury Regulations section 1.410(b)‑7(c) and, if the Administrative Committee chooses, the permissive aggregation rules of Treasury Regulations section 1.410(b)‑7(d), provided that any aggregated plans shall use the same testing method under Treasury Regulations section 1.401(k)‑2(a)(2)(ii) (i.e., current year or prior year testing method) as is used by the Plan for the Plan Year. Notwithstanding the foregoing, effective January 1, 2004, the mandatory disaggregation rules relating to the ESOP and non‑ESOP portions of the Plan shall not apply.

(1) If, after application of the mandatory disaggregation rules, in the preceding paragraph, this Plan is permissively aggregated with one or more other plans that include matching or after‑tax contributions subject to contribution testing under Code section 401(m) for purposes of Code section 401(a)(4) or 410(b), then this Plan and such other plans shall be treated as one arrangement for purposes of this Plan section.

(2) In determining whether the restrictions of this Plan section are met, the Administrative Committee may exclude from the ACP Test all Eligible Employees who are not Highly Compensated Employees and who have not met the minimum age and service requirements of Code section 410(a)(1)(A), if the Administrative Committee elects to apply Code section 410(b)(4)(B). Alternatively, the Administrative Committee may apply the ACP Test separately to all Eligible Employees who have not met the minimum age and service requirements of Code section 410(a)(1)(A).

(b) ACP Test. The Average Contribution Percentage for the Plan Year of Participants who are Highly Compensated Employees shall not exceed the greater of:

(1) The product of 1.25 and the Average Contribution Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year; or

(2) The lesser of:

(A) The product of two and the Average Contribution Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year, or

(B) The Average Contribution Percentage for the current Plan Year for the Eligible Employees who are not Highly Compensated Employees for the current Plan Year plus two percentage points.

By an amendment to the Plan, the Administrative Committee may elect to apply paragraphs (1) and (2) by using the Average Contribution Percentage of Employees who are not Highly Compensated Employees for the preceding Plan Year rather than the current Plan Year except that such election may not be changed unless permitted by the Internal Revenue Service.

(c) The restrictions of this section shall be based on the Participant’s actual Testing Compensation while an Active Participant and total Matching Contributions, After‑Tax Contributions and Adjustment Contributions allocated to the Participant’s Account for the Plan Year. The Administrative Committee is authorized to restrict the After‑Tax Contributions of Highly Compensated Employees in a uniform manner if it determines, based on advance testing done during the Plan Year, that such restriction is necessary or appropriate to assure final Plan Year compliance with restrictions of this section.

6.5 Corrective Measures if ACP Test Failed

If, at the end of the Plan Year, the Administrative Committee determines that the Average Contribution Percentage of Highly Compensated Employees exceeds the maximum permitted for the Plan Year under the ACP Test, then the Administrative Committee shall take the corrective steps described in this Plan section so that the requirements of Plan section 6.4 are met for the Plan Year. Matching Contributions, After‑Tax Contributions, and Adjustment Contributions, along with any other matching contributions and after‑tax contributions (including any recharacterized elective deferrals) made to other Qualified Plans that are included the Actual Deferral Percentage of a Highly Compensated Employee, exceeding the ACP Test limits are referred to as Excess Aggregate Contributions.

(a) Correction Method. The Administrative Committee shall distribute or forfeit Excess Aggregate Contributions, along with allocable investment gains and losses, pursuant to Treasury Regulations section 1.401(m)‑2(b)(2) and this Plan section.

(b) Determining Total Excess Aggregate Contributions. The amount of Excess Aggregate Contributions attributable to each Highly Compensated Employee is the amount by which Matching Contributions, After‑Tax Contributions and Adjustment Contributions, along with any other matching contributions and after‑tax contributions (including any recharacterized elective deferrals) made to other Qualified Plans that are included the Average Contribution Percentage of a Highly Compensated Employee, must be reduced so that the Average Contribution Percentage for that Highly Compensated Employee is reduced to the maximum permissible Average Contribution Percentage for Highly Compensated Employees. The maximum permissible Average Contribution Percentage for Highly Compensated Employees is determined by reducing the Average Contribution Percentage for the Highly Compensated Employee with the highest Average Contribution Percentage for the Plan Year to the Average Contribution Percentage for the Highly Compensated Employee with the next highest Average Contribution Percentage. If a lesser reduction would enable the ACP Test to be satisfied, only the lesser reduction is used to determine the maximum permissible Average Contribution Percentage. This procedure is repeated until the ACP Test would be satisfied. The total amount of Excess Aggregate Contributions to be corrected is equal to the sum of the dollar amounts computed under this subsection for each Highly Compensated Employee and is be referred to as the Total Excess Aggregate Contributions.

(c) Apportionment of Total Excess Aggregate Contributions. Total Excess Aggregate Contributions for the Plan Year shall be apportioned as provided in this subsection.

(1) Excess Aggregate Contributions allocated to the Highly Compensated Employee with the highest dollar amount of Matching Contributions, After‑Tax Contributions and Adjustment Contributions taken into account under the ACP Test for the Plan Year shall be reduced by the amount required to cause that Highly Compensated Employee’s remaining amount of Matching Contributions, After‑Tax Contributions and Adjustment Contributions for the Plan Year to be equal to the dollar amount of Matching Contributions, After‑Tax Contributions and Adjustment Contributions for the Highly Compensated Employee with the next highest dollar amount. This amount shall be allocated as the Excess Aggregate Contribution for the Highly Compensated Employee, unless a smaller reduction, when added to the total dollar amount already allocated as Excess Aggregate Contributions for other Highly Compensated Employees pursuant to this procedure equals the Total Excess Aggregate Contributions for the Plan Year.

(2) If a Highly Compensated Employee’s Excess Aggregate Contributions include matching contributions and after‑tax contributions (including any recharacterized elective deferrals) made to other Qualified Plans that are included the Average Contribution Percentage of a Highly Compensated Employee, then the Excess Aggregate Contribution of that to the Highly Compensated Employee shall not exceed the Matching Contributions, After‑Tax Contributions and Adjustment Contributions made under this Plan for the Plan Year. Any portion of the Total Excess Aggregate Contributions which is apportioned to a Highly Compensated Employee pursuant to this subsection, but which cannot be corrected because of the preceding sentence, shall be apportioned to the Highly Compensated Employee with the next lowest total dollar amount of Pre-Tax Deferrals and/or Roth Contributions and that Highly Compensated Employee’s Excess Aggregate Contributions shall be reduced by an amount which includes the amount not corrected for the other Highly Compensated Employee.

(3) If the total amount corrected under this subsection is less than the Total Excess Aggregate Contributions for the Plan Year, the procedure in this paragraph shall be repeated until the total amount corrected is equal to the Total Excess Aggregate Contributions for the Plan Year.

(4) The investment gains and losses allocable to the Excess Aggregate Contributions are equal only to the sum of allocable investment gains and losses for the Plan Year for which the distribution is made. The allocable investment gain or loss attributable to the Excess Aggregate Contributions may be determined in accordance with any of the methods permitted under Treasury Regulations section 1.401(m)–2(b)(2)(iv), disregarding any provisions relating to the distribution of gap period earnings, and may be determined up to seven days before the date of the correction.

(d) Distribution or Forfeiture. Excess Aggregate Contributions shall not be treated as corrected even if distributed under this subsection, unless the requirements of this subsection are met.

(1) Excess Aggregate Contributions and allocable investment gains and losses must be distributed to the Highly Compensated Employee to whom it has been allocated within 12 months after the close of the Plan Year for which the Excess Aggregate Contribution arose.

(2) Excess Aggregate Contributions and allocable investment gains and losses shall be distributed or, to the extent attributable to Matching Contributions in which the Highly Compensated Employee is not fully vested as of the end of the Plan Year, forfeited in the following order:

(A) After‑Tax Contributions and allocable investment gains and losses on which Matching Contributions were not made;

(B) Adjustment Contributions and allocable investment gains and losses on which Matching Contributions were not made;

(C) After‑Tax Contributions and allocable investment gains and losses along with the corresponding Matching Contributions and allocable investment gains and losses; and

(D) Adjustment Contributions and allocable investment gains and losses along with the corresponding Matching Contributions and allocable investment gains and losses.

(3) The distributed Excess Aggregate Contributions and allocable investment gains and losses shall be taken from the Investment Funds in which the subaccount is then invested on a pro rata basis.

(4) If the Highly Compensated Employee received a full distribution of his or her Account before Excess Aggregate Contributions and allocable investment gains and losses is distributed to the Highly Compensated Employee, then the prior distribution shall be reported for taxation purposes as first a correction of Excess Aggregate Contributions and allocable investment gains and losses to the extent required under this Plan section.

(5) A distribution of Excess Aggregate Contributions and allocable investment gains and losses shall in no event be treated as satisfying a required minimum distribution for purposes of Code section 401(a)(9) and Plan section 7.6.

(6) The distribution required by this Plan section may be made notwithstanding any other Plan provision.

6.6 Limitation on Annual Additions

(a) General Rule. Notwithstanding anything to the contrary contained in this Plan, the total Annual Additions under this Plan and any other defined contribution plan, as defined in Code section 414(i), maintained by the Company or any Affiliate, allocated to a Participant’s Account for any Plan Year, which shall be the limitation year for purposes of Code section 415, shall not exceed the lesser of:

(1) $40,000, as adjusted for increases in the cost‑of‑living under Code section 415(d) for Plan Years beginning after 2002; or

(2) 100 percent of the Participant’s Section 415 Compensation for the limitation year.

(b) “Annual Addition” Defined. The term “Annual Addition,” with respect to any Participant for a Plan Year, shall mean the aggregate of:

(1) The amount of Employer contributions (including Matching Contributions and Pre-Tax Deferrals and Roth Contributions other than Catch‑Up Contributions) allocated to the Participant’s Account under this Plan and any other Employer contributions (other than Catch‑Up Contributions under Code section 414(v)) allocated under any other defined contribution plan, as defined in Code section 414(i), maintained by the Company or any Affiliate for the Plan Year;

(2) The amount of a Participant’s After‑Tax Contributions (including Adjustment Contributions, but excluding Rollover, Roth Rollover and After-Tax Rollover Contributions) allocated to the Participant’s Account under this Plan and any other Employee contributions allocated under any other defined contribution plan maintained by the Company or any Affiliate for the Plan Year;

(3) Forfeitures allocated to the Participant’s Account under this Plan or any other defined contribution plan maintained by the Company or any Affiliate for the Plan Year; and

(4) For the purpose of Plan section 6.6(a)(1) only, the amount of Employer contributions, if any, allocated to an account described in Code section 419A(d)(1) or an account described in Code section 415(l)(2).

For purposes of this subsection and to comply with the requirements of Code section 415(h), the term “Affiliate” includes, in addition to Affiliates defined in Plan section 2.1(i), any entity that would be an Affiliate under that definition if the phrase “more than 50 percent” were substituted for the phrase “at least 80 percent” each place it appears in Code 1563(a)(1).

(c) Additional Rules. In applying the limits of subsection (a), the following rules shall apply:

(1) Excess Deferrals shall not be included as an Annual Addition if they are distributed in a corrective distribution under the provisions of that section. However, any Excess Deferrals that are not distributed in a corrective distribution under Plan section 6.1 shall be included as an Annual Addition, even if they are in excess of the Code section 402(g)(1) limit.

(2) Pre-Tax Deferrals and Roth Contributions in excess of the ADP Test limits of Plan section 6.2 shall be included as an Annual Addition, even if they are correctively distributed or re‑characterized as Adjustment Contributions under Plan section 6.3.

(3) Matching Contributions and After‑Tax Contributions (including any Adjustment Contributions) in excess of the ACP Test limits of Plan section 6.4 shall be included as an Annual Addition, even if they are correctively forfeited or distributed under Plan section 6.5. Matching Contributions relating to distributions of Excess Deferrals under Plan section 6.1(d) are forfeited and shall not be included as an Annual Addition.

(4) If a short limitation year is created because of an amendment or other action changing the limitation year (or Plan Year) to a different 12‑consecutive‑month period, the dollar limitation of Plan section 6.6(a)(1) to be applied for that short limitation year shall be multiplied by a fraction, the numerator of which is the number of months in the short limitation year and the denominator of which is 12.

(5) The Annual Additions of a Participant who is also a Supplemental Plan Participant for the Plan Year shall be determined under this paragraph if doing so results in a larger amount of Annual Additions for that Participant for the Plan Year. Annual Additions under this paragraph shall be determined by assuming that, for the Plan Year, the Participant contributed the contribution percentage limit in effect for the Participant as determined under Appendix E and received the maximum allocation of Matching Contribution under Plan section 5.2.

(d) Disposition of Excess Annual Additions

(1) Not a Supplemental Plan Participant. If the Participant is not also a Supplemental Plan Participant for the Plan Year, then the Participant’s Annual Additions shall be reduced under this Plan, if such reduction is required for purposes of reducing allocations on a combined basis, to the limits of subsection (a) and Code section 415(c), as follows:

(A) First, by distributing After‑Tax Contributions (including any Adjustment Contributions) made for the Plan Year to the Participant, to the extent necessary; and

(B) Next, by distributing Pre-Tax Deferrals and/or Roth Contributions made for the Plan Year to the Participant, to the extent necessary; and

(C) Then, forfeiting Matching Contributions made for the Plan Year, to the extent necessary; and

(D) Finally, reducing any remaining excess Annual Additions under the terms of such other defined contribution plans maintained by the Company or any Affiliate as specified in those plans.

(2) Supplemental Plan Participant. If the Participant is also a Supplemental Plan Participant for the Plan Year, then the Participant’s Annual Additions shall first be reduced under the terms of the Retirement Plan for the Plan Year by reducing the allocations made under the Retirement Plan to the extent necessary to assure compliance with the limits of subsection (a) and Code section 415(c). Only after reductions under the Retirement Plan have been made shall reductions of Annual Additions be made under the terms of this Plan and such other defined contribution plans maintained by the Company or any Affiliate, if such a reduction is required for purposes of reducing allocations on a combined basis, to the limit of subsection (a) and Code section 415(c), as follows:

(A) First, by distributing After‑Tax Contributions (including any Adjustment Contributions) made for the Plan Year to the Participant, to the extent necessary; and

(B) Next, by distributing Pre-Tax Deferrals and/or Roth Contributions made for the Plan Year to the Participant, to the extent necessary; and

(C) Then, forfeiting Matching Contributions made for the Plan Year, to the extent necessary; and

(D) Finally, reducing any remaining excess Annual Additions under the terms of such other defined contribution plans (other than the Retirement Plan) maintained by the Company or any Affiliate as specified in those plans.

(e) Adjustment of Allocations. If an allocation to the Account of a Participant would exceed the limit of subsection (a) due to a reasonable mistake in estimating a Participant’s Section 415 Compensation or due to forfeitures or a reasonable error in the estimation of salary deferrals, then any amount which cannot be allocated shall be held in a suspense account and shall be allocated to the Account of such Participant in the next following Plan Year. The suspense account shall not share in investment gains or losses of the Trust Fund. Effective for Plan Years beginning after July 1, 2007, this subsection shall no longer apply because this correction methodology is no longer permitted under the final Treasury Regulations under Code section 415.

6.7 Limitation on Pay Taken Into Account

(a) In determining the amount of Pre-Tax Deferrals and Roth Contributions that may be made on behalf of a Participant for a Plan Year, the total amount of Earnings to which the percentage reduction, elected by the Participant, is applied shall not be limited. Notwithstanding the foregoing, however, the total annual amount of Pre-Tax Deferrals and Roth Contributions made for a Plan Year on behalf of the Participant shall not exceed the product of the maximum deferral percentage allowed under the Plan for the Plan Year multiplied by the compensation limit in effect for the Plan Year under Code section 401(a)(17).

(b) In determining the amount of After‑Tax Contributions that may be made on behalf of a Participant for a Plan Year, the total amount of Earnings to which the percentage reduction, elected by the Participant, is applied shall not be limited. Notwithstanding the foregoing, however, the total annual amount of After‑Tax Contributions made for a Plan Year on behalf of the Participant shall not exceed the product of the maximum contribution percentage allowed under the Plan for the Plan Year multiplied by the compensation limit in effect for the Plan Year under Code section 401(a)(17).

(c) In determining the amount of Matching Contributions that may be made on behalf of a Participant for a Plan Year, the total amount of Earnings to which the Matching Contribution is applied shall not be limited. Notwithstanding the foregoing, however, the total annual amount of Matching Contributions made for a Plan Year on behalf of an Active Participant shall not exceed the product of the matching percentage determined under Appendix F multiplied by the maximum amount of Earnings for which Matching Contributions are determined multiplied by the compensation limit in effect for the Plan Year under Code section 401(a)(17).

6.8 Deductibility Limitation

Notwithstanding any provision of the Plan to the contrary, the dollar amount of Employer contributions to this Plan are conditioned on their deductibility under Code section 404 and, thus, shall always be limited to the amount deductible under Code section 404 for the taxable year for which such contributions are paid to the Trust Fund.

Article 7. Benefit Distributions

7.1 Distributions Generally

Distribution of a Participant’s vested Account may begin pursuant to Plan section 7.2, relating to in‑service withdrawals, Plan section 7.3, relating to benefit payments on account of a Separation from Service, and Plan section 7.5, relating to death benefit distributions, as applicable under the terms of this Article, but not later than the date provided in Plan section 7.6, relating to required minimum distributions.

Notwithstanding the foregoing, a Participant’s Pre-Tax Account and Roth Account may not be distributed earlier than upon one of the following events:

(a) The Participant’s retirement, death, Disability, or Separation from Service;

(b) The termination of the Plan without the establishment of another defined contribution plan (other than an employee stock ownership plan within the meaning of Code section 4975(e)(7)), provided that distributions made under this paragraph may be made only in the form of a single lump sum that complies with Code section 401(k)(10)(B); or

(c) The Participant’s attainment of age 59½ or, if the Plan is amended to so provide, a financial hardship of the Participant.

7.2 In‑Service Withdrawals

(a) An Active Participant or Inactive Participant may withdraw, prior to his or her Separation from Service, in the following order, any amount, up to 100 percent of the sum of the Participant’s:

(1) After-Tax Rollover Account, if any;

(2) After‑Tax Account, if any;

(3) Rollover Account, if any;

(4) Pre-Tax Account, but only if the Participant has attained age 59½; and then

(5) Matching Account, but only if the Participant has completed at least three years of Service.

(b) An Active Participant or Inactive Participant also may withdraw, prior to his or her Separation from Service, any amount, up to 100 percent of the sum of the Participant’s, without regard to Plan section 7.2(e) below:

(1) Roth Account, but only if the Participant has attained age 59½;

(2) Roth Rollover Account; or

(3) In-Plan Roth Rollover Account, but only if the Participant has attained age 59½.

(c) No withdrawal may be requested in any processing period in which a plan loan, as described in Article 8, is being processed. Furthermore, no withdrawal request may be processed more often than once in any six‑month period beginning with the date that the Participant’s most recent withdrawal request was processed. Effective August 8, 2016, there will be no restriction on the timing of withdrawal requests or the coordination of withdrawal requests with the processing of loan or other requests under the Plan.

(d) Application for a withdrawal shall be made on such forms as the Administrative Committee prescribes and shall be effective as of the end of the processing period in which such application is received and approved by the Administrative Committee. The Administrative Committee shall direct the Trustee, in such cases, to pay the Participant or Inactive Participant the withdrawal amount in a single sum.

(e) Withdrawals shall be paid first out of the net cumulative pre‑1987 contributions from the After‑Tax Account. Withdrawals shall then be paid out of the net cumulative post‑1986 contributions, together with earnings thereon, on a pro rata basis, from the After‑Tax Account. Additional amounts shall be withdrawn, if needed, from earnings on pre‑1987 contributions from the After‑Tax Rollover Account, if any, then from the After-Tax Account, if any, then from the Rollover Account, if any, then from the Pre-Tax Account, if permissible, and then from the Matching Account, to the extent permissible. The amount withdrawn shall be taken from such Investment Funds in which the subaccount is invested on a pro rata basis.

(f) A withdrawal from a Participant’s Account balances invested in Oxy Stock shall be in the form of full shares of Oxy Stock and cash representing any fractional share, except that cash shall be paid in lieu of full shares of Oxy Stock if the Participant specified in the written request for withdrawal that the withdrawal be in the form of cash. A withdrawal from Account balances invested in assets other than Oxy Stock shall be paid in cash. Notwithstanding the foregoing, a withdrawal consisting of pre‑1987 contributions from the After‑Tax Account only shall be in the form of cash.

(g)

(1) Except as provided below, if a Participant withdraws any amount from the Matching Account, the Participant (other than a Participant who has attained age 59½ at the time the withdrawal is requested and who withdraws the entire balance in his or her Account) shall not be permitted to make any Pre-Tax Deferrals, Catch-Up Contributions, Roth Contributions, After‑Tax Contributions, or receive Matching Contributions for a period of six calendar months after the withdrawal is processed (except that such Participant will still be eligible to receive Matching Contributions on any Annual Bonus). Effective for withdrawals requested after August 8, 2016, if a Participant is suspended from making any Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions, and/or After‑Tax Contributions in accordance with the sentence above, such contributions will be automatically reinstated upon expiration of the six-month suspension period at the Default Percentage, as applicable, or if the Participant was not subject to automatic enrollment or had opted out of automatic enrollment at the percentage in place prior to the suspension. Effective January 1, 2017, unless the Participant affirmatively elects otherwise, with respect to any Participant hired prior to August 5, 2016, upon re-instatement, the election in effect as of August 5, 2016 will apply to any Annual Bonus paid in the 2017 Plan Year and any subsequent plan year until the Participant affirmatively elects otherwise. Effective August 8, 2016, any Participant subject to automatic enrollment pursuant to Plan section 4.6, must make a separate election to make Pre-Tax Deferrals, Roth Contributions and After-Tax Contributions from Participant’s Annual Bonus.

(2) The preceding subsection shall be inapplicable in the case of a withdrawal effected by a creditor of a Participant pursuant to any insolvency proceeding initiated under federal or state law or pursuant to any tax levy.

(3) In addition, notwithstanding the foregoing and effective January 1, 2013, a Participant who has attained age 59½ and who withdraws less than the entire balance in his or her Account, shall not be suspended from making Pre-Tax Deferrals, Roth Contributions, Catch‑Up Contributions, After‑Tax Contributions, or receiving Matching Contributions, but pursuant to subsection (b) shall not be permitted to make another withdrawal for six months beginning with the date that the Participant’s most recent withdrawal request was processed. Effective August 5, 2016, a Participant who has attained age 59½ and who withdraws less than the entire balance in his or her Account will no longer be subject to the one withdrawal per six-month period limitation.

7.3 Benefits Upon Separation from Service

(a) Every Participant who incurs a Separation from Service for any reason other than death may elect to receive a distribution of the vested portion of his or her Account, in a payment form specified by Plan section 7.4. The failure of a Participant to elect a distribution of benefits upon his or her Separation from Service shall be deemed to be an election by the Participant to defer the commencement of benefits.

(b) Unless the Participant chooses to defer the commencement of benefits, either affirmatively or by failing to make a distribution election, and subject to Plan section 7.6, distribution of benefits to a Participant who incurs a Separation from Service shall begin no later than the 60^th day after the close of the Plan Year in which occurs the later of:

(1) The Participant’s Separation from Service; or

(2) The Participant’s 65^th birthday.

If for any reason the amount which is required to be paid cannot be ascertained on the date payment would be due hereunder, payment or payments shall be made not later than 60 days after the earliest date on which the amount of such payment is ascertained.

7.4 Payment Rules

(a) General Rules. All distributions from this Plan shall be valued as provided in Article 10 and paid in cash or Oxy Stock as provided in this Plan section. The automatic form of benefit payment to a Participant who has incurred a Separation from Service and elected a distribution of his or her vested Account is a single lump sum.

(b) Election Procedures. All Participant elections to commence benefits shall be made during an election period of not more than 90 days and, except as provided below, not less than 30 days ending on the day prior to the date as of which his benefits are scheduled to commence in accordance with the benefit payment election procedures prescribed by the Administrative Committee. Such procedures shall require the following:

(1) An election form shall be provided to the Participant in non‑technical language which will contain a general description of the distribution options.

(2) A Participant may revoke an election of any benefit form described in this section and choose again to take any available benefit form at any time and any number of times within the above election period.

(3) A Participant, after having received the written description described in this subsection, may reject the automatic form of benefit and elect a different option under subsection (c), even though the written description was provided less than 30 days prior to the Participant’s benefit commencement date, so long as the conditions contained in Treasury Regulations section 1.417(e)‑1T(b)(3)(ii) have been met. If the Participant makes an untimely request for additional information, the Administrative Committee, at its discretion, may grant such request, but the granting of such request shall not result in the extension of the election period.

(c) Optional Payment Forms. A Participant who has incurred a Separation from Service for any reason other than death may elect to have his or her vested Account distributed to the Participant under one of the following distribution options, in lieu of the automatic lump sum, as selected by the Participant in the manner prescribed and approved by the Administrative Committee:

(1) Partial Cash Distribution. A request for a specified dollar portion of the Participant’s vested Account. A Participant may request one partial cash distribution in any six‑month period. If the Participant receives a partial cash distribution, the Participant must wait until the next processing period before he or she may request a subsequent lump sum payment or total distribution. Effective August 8, 2016, there will be no timing limitation for partial cash distributions. A Participant may elect a partial cash distribution under one of the following options; Investment Fund balances will automatically be depleted on a pro rata basis in the following account depletion sequence:

(A) Option 1.

(i) After‑Tax Rollover Account;

(ii) After-Tax Account;

(iii) Rollover Account; and

(iv) Pre-Tax Account;

(B) Option 2

(i) Matching Account;

(ii) Roth Rollover Account;

(iii) In-Plan Roth Rollover Account; and

(iv) Roth Account.

(C) Or under both (A) and (B) above.

Remaining balances in each account will continue to participate in Investment Fund earnings until valued for distributions as provided in Article 10.

(2) Special Distribution. The portion of Participant’s vested Account, which is an Eligible Rollover Distribution (as determined under Plan section 7.7(b)(4)) and which is invested in Investment Funds other than the Oxy Stock Fund, is distributed as a Direct Rollover (within the meaning of Plan section 7.7(b)(1)), as directed by the Participant. The Oxy Stock Fund balance from the Participant’s vested Account is distributed to the Participant as shares of Oxy Stock along with a cash distribution of any remaining portion of the Participant’s vested Account.

(3) Total Deferral. Defers distribution of the Participant’s vested Account, but not beyond the end of the year in which the Participant attains age 70½. Subject to Plan section 7.6, the Participant may revoke his or her deferral election at any time by submitting another distribution request.

(d) Reserved.

(e) Payment Medium. The provisions of this subsection are intended to comply with the stock distribution requirements of Code sections 409(h) and 409(o) applicable to the portion of this Plan constituting an employee stock ownership plan, as required by Code section 4975(e)(7). Notwithstanding any Plan provision to the contrary, the Administrative Committee shall take steps to ensure that this section is interpreted and administered so as to comply with such requirements. In the event of any conflict, the rules of the Code and Treasury Regulations shall control.

(1) General Rule. In the case of a Participant, Beneficiary or Alternate Payee receiving a distribution in the form of single lump sum payment, the value of the vested Account attributable to investments other than Oxy Stock shall be paid in cash and the value of the vested Account attributable to Oxy Stock shall be distributed in full shares of Oxy Stock plus cash representing the value of any fractional share, except as provided in Plan section 7.4(h)(3) for mandatory cashout distributions and Plan section 7.6(a) for required minimum distributions.

(2) Alternative Elections.

(A) By written notice to the Administrative Committee, the Participant, Beneficiary or Alternate Payee may elect to receive cash in lieu of and equal to the value of the Oxy Stock that would otherwise be distributed under the general rule.

(B) By written notice to the Administrative Committee, a Participant, Beneficiary or Alternate Payee may elect to receive all or a portion of the vested Account in the form of whole shares of Oxy Stock, plus cash for any fractional share. Any such election shall be implemented in accordance with procedures established by the Administrative Committee by transferring the investment of such Account or portion thereof, as applicable, (including without limitation amounts transferred from the MidCon Corp. ESOP) as soon as practicable to the Oxy Stock Fund and distributing such amounts as soon as practicable thereafter.

(3) Put Option.

(A) Oxy Stock is readily tradable on established securities market within the meaning of Treasury Regulation section 1.401(a)(35)-1(f)(5). Thus, the provisions of this paragraph (3) shall apply only in the event and to the extent that as of the date of distribution of Oxy Stock, the Oxy Stock is not readily tradable on established securities market or is subject to a trading limitation.

(B) If Oxy Stock is not readily tradable on established securities market or is subject to a trading limitation when distributed, the distributee shall have the option to sell (the “put option”) such Oxy Stock, in whole or in part, to the Company. The put option shall be granted in accordance with Code section 409(h) and all applicable Treasury Regulations. Specifically, the put option shall provide that for a period of at least 60 days following the date of distribution of the Oxy Stock and, if not exercised within such period of 60 days, during the first 60 days in the following Plan Year, the distributee shall have the right to have the Company purchase such shares at their fair market value, determined in accordance with Treasury Regulations section 54.4975-11(d)(5), as of the Valuation Date coincident with or immediately preceding the date of exercise of such put option. The put option may be exercised by notifying the Employer in writing that the option is being exercised.

(C) Once the put option is exercised, the fair market value of such shares shall be paid in a lump sum as soon as practicable. Notwithstanding the foregoing, the Company reserves the right to adopt a different payment schedule at any time, but such payment schedule shall not be longer than in annual installments over a period of five years, with interest on the deferred balance at a reasonable rate as determined by the Administrative Committee; provided that any purchase of stock having a value of $1,000 or less shall be paid for in a lump sum.

(D) The provisions of this paragraph (3) shall continue to apply to Oxy Stock if the Oxy Stock Fund ceases to be an employee stock ownership plan within the meaning of Code section 4975(e)(7).

(E) Notwithstanding the foregoing, this paragraph (3) need not apply to that portion of an Account which the Participant has elected to invest under the diversification provisions of Plan section 9.5.

(f) Payments to Alternate Payees. To the extent permitted by the terms of a Qualified Domestic Relations Order, amounts assigned to an Alternate Payee may be paid as soon as possible in a lump sum, notwithstanding the age, employment status, or other factors affecting the ability of the Participant to make a withdrawal or otherwise to receive a distribution of amounts allocated to the Participant’s Account, provided that the total amount assigned to an Alternate Payee does not exceed $5,000 at the time the amount is distributed or, if the amount assigned does exceed $5,000, the Alternate Payee consents in writing to the distribution. Only if required under the Qualified Domestic Relations Order, an Alternate Payee’s Account may be distributed under one of the optional payment forms specified in subsection (c), if elected by the Alternate Payee in accordance with procedures established by the Administrative Committee. Notwithstanding the foregoing, the Alternate Payee shall be paid in no event no later than the dates specified in Plan section 7.6 (relating to required minimum distributions).

(g) Special Rules for Former Laurel Plan Accounts.

(1) In the case of a Participant for whom a direct plan‑to‑plan transfer was made to this Plan from the Laurel Industries Inc. Incentive Savings Plan (the “Laurel Plan”), distribution may be made, at the election of the Participant, in any form described in section 6.5(b)(2) of the Laurel Plan as in effect on December 31, 1996, provided that the amount subject to such election shall not exceed the amount of the Participant’s Account attributable to such transfer.

(2) In the case of a Beneficiary of a Participant for whom a direct plan‑to‑plan transfer was made to this Plan from the Laurel Industries Inc. Incentive Savings Plan (the “Laurel Plan”), distribution may be made, at the election of the Beneficiary, in any form described in section 6.6(g)(1)(ii) of the Laurel Plan as in effect on December 31, 1996, provided that the amount subject to such election shall not exceed the amount of the Beneficiary’s Account attributable to such transfer.

(h) Mandatory Cashout Distribution. Notwithstanding the election procedures set forth above in Plan section 7.4(b):

(1) Distribution Less Than or Equal to $1,000. Effective October 1, 2015, if the vested Account of a terminated Participant is equal to or less than $1,000 when the amount thereof is first determined, the entire amount shall be distributed in a lump sum as promptly as possible.

(2) Distribution Less Than or Equal to $5,000. Effective as of August 8, 2016, if the vested Account of a terminated Participant is less than or equal to $5,000 when the amount thereof is first determined, and the Participant fails to elect to have his or her benefits paid directly or in the form of a Direct Rollover (within the meaning of Plan section 7.7(b)(1)) to an Eligible Retirement Plan (within the meaning of Plan section 7.7(b)(3)), the entire account shall be distributed as an automatic rollover to an individual retirement account designated by the Administrative Committee. The Participant will be notified in writing regarding the identity of the individual retirement account trustee or issuer and that his distribution may be transferred without cost or penalty to another individual retirement account.

(3) Distribution to Beneficiaries, Alternate Payees or Participants Over Age 62. Notwithstanding Plan section 7.4(h)(2) above, any distribution that is less than or equal to $5,000 and payable to a Beneficiary, Alternate Payee or Participant who is over age 62 will be distributed in a lump sum as promptly as possible and will not be distributed as an automatic rollover to an individual retirement account.

(4) Form of Distribution. All mandatory cashout distributions will be made in cash and there will be no requirement to issue any shares of Oxy Stock.

7.5 Death Benefits

(a) Participant’s Death After Benefit Commencement. If the Participant dies after distribution of his or her vested Account has commenced, the remaining portion of such benefit, if any, will continue to be distributed at least as rapidly as under the method of distribution in effect prior to the Participant’s death.

(b) Participant’s Death Before Benefit Commencement. Upon the death of a Participant before benefit payments begin, the balance of the deceased Participant’s Account shall be distributed to the Participant’s Beneficiary as soon as practicable after the Participant’s death. Notwithstanding the foregoing, a Beneficiary who is the Participant’s Spouse may elect, before any benefit payments begin, in accordance with procedures established by the Administrative Committee, to defer receipt of payment of the deceased Participant’s Account, until the year in which the Participant would have attained age 70½ in accordance with Plan section 7.6(c)(2).

(1) If the Participant’s Beneficiary is a trust or estate, the distribution shall be paid in a single lump sum payment.

(2) If the Beneficiary is other than the Participant’s Spouse and unless the Beneficiary elects otherwise, the distribution shall be paid in a single lump sum.

(3) If the Beneficiary is the Participant’s Spouse, then in addition to the payment form described in paragraph (2), the Spouse may elect, in accordance with procedures established by the Administrative Committee, to have the distribution paid in the form of a partial cash distribution, as described in Plan section 7.4(c)(1).

(c) Death of Alternate Payee or Beneficiary. If an Alternate Payee or a Beneficiary of a deceased Participant or Alternate Payee dies prior to distribution of the separate Account established on behalf of the Alternate Payee or Beneficiary, the balance of the deceased individual’s Account shall be distributed to his or her Beneficiary as soon as practicable after his death. Such distribution shall be made in the form of a lump sum payment.

7.6 Required Minimum Distributions

This section applies for purposes of determining required minimum distributions for distribution Plan Years beginning on or after January 1, 2003. In other words, this section provides the latest time for distributions to be made or commenced. Other Plan provisions may specify earlier dates for distributions and such provisions shall govern to the extent they are consistent with this section. This section, however, takes precedence over any inconsistent Plan provision. All distributions required under this section shall be determined and made in accordance with Code section 401(a)(9) and the Treasury Regulations thereunder, including the minimum distribution incidental benefit requirements, which are incorporated herein by this reference. For purposes of this Plan section, the required minimum distribution amount shall be determined based on the Account balance as of the last Accounting Date in the Plan Year immediately preceding the Distribution Calendar Year, increased by contributions made and allocated as of dates in the Plan Year after the last Accounting Date, if any, and reduced by distributions made in the Plan Year after the last Accounting Date, if any. The Account balance for the Plan Year immediately preceding the Distribution Calendar Year includes any amounts rolled over or transferred to the Plan in the Plan Year.

(a) Form of Distribution. Unless the Participant’s Account is distributed in a single sum on or before the Required Beginning Date, as of the first Distribution Calendar Year, distributions will be made in accordance with subsections (b) and (c). All required minimum distributions will be made in cash, and there will be no requirement to issue any shares of Oxy Stock.

(b) Required Minimum Distributions During Participant’s Lifetime. The Participant’s entire Account will be distributed, or begin to be distributed, to the Participant no later than the Participant’s Required Beginning Date. During the Participant’s lifetime, the minimum amount that will be distributed for each Distribution Calendar Year is the amount determined under the default rule of paragraph (1) or, if the Participant satisfies the conditions in a timely manner, under the alternative rule of (2):

(1) Default Rule. The quotient obtained by dividing the Participant’s Account balance by the distribution period in the Uniform Lifetime Table set forth in Treasury Regulations section 1.401(a)(9)‑9, using the Participant’s age as of the Participant’s birthday in each Distribution Calendar Year.

(2) Alternative Rule. If the Participant’s sole Beneficiary for the Distribution Calendar Year is the Participant’s Spouse, the quotient obtained by dividing the Participant’s Account balance by the number in the Joint and Last Survivor Table set forth in Treasury Regulations section 1.401(a)(9)‑9, using the Participant’s and Spouse’s attained ages as of the Participant’s and Spouse’s birthdays in the Distribution Calendar Year. For this alternative rule to apply, the Participant must request its application and provide such proof of marriage and the Spouse’s age, at such time and in such manner as the Administrative Committee may reasonably require, in advance of the Distribution Calendar Year.

Required minimum distributions will be determined under this subsection beginning with the first Distribution Calendar Year and redetermined for each subsequent Distribution Calendar Year up to and including the Distribution Calendar Year that includes the Participant’s date of death.

(c) Required Minimum Distributions After Participant’s Death.

(1) Death of Participant On or After Date Distributions Begin.

(A) Participant Survived by One Beneficiary. If the Participant dies on or after the date distributions begin and there is a sole Beneficiary, the minimum amount that will be distributed for each Distribution Calendar Year after the year of the Participant’s death is the quotient obtained by dividing the Participant’s Account balance by the remaining Life Expectancy, determined as follows:

(i) If the Participant is not married or the sole Beneficiary is not the Participant’s surviving Spouse, the remaining Life Expectancy is calculated using the age of the Participant in the year of death, reduced by one for each subsequent year.

(ii) If the Participant’s surviving Spouse is the Participant’s sole Beneficiary, the remaining Life Expectancy of the surviving Spouse is calculated for each Distribution Calendar Year after the year of the Participant’s death using the surviving Spouse’s age as of the Spouse’s birthday in that year. For the Distribution Calendar Year after the year of the surviving Spouse’s death, any remaining payment shall be made in a single sum to the Spouse’s estate.

(B) Participant Survived by More Than One Beneficiary. If the Participant dies on or after the date distributions begin and there is more than one Beneficiary as of September 30 of the year after the year of the Participant’s death, the Participant’s remaining Account shall be paid in a single sum as required by Plan section 7.5.

(C) No Beneficiary Survives the Participant. If there is no Beneficiary as of September 30 of the year after the year of the Participant’s death, the Participant’s remaining Account will be paid in a single sum to the Participant’s estate no later than the Distribution Calendar Year after the Participant’s death.

(2) Death of Participant Before Date Distributions Begin. If the Participant dies before distributions begin, the Participant’s Account balance will be distributed, or begin to be distributed no later than provided in this paragraph. The minimum amount that will be distributed or begin to be distributed for each Distribution Calendar Year after the year of the Participant’s death is the amount determined in paragraph (1) above.

(A) If the Participant’s surviving Spouse is the Participant’s sole Beneficiary, then distributions to the surviving Spouse will begin no later than:

(i) December 31 of the calendar year immediately following the calendar year in which the Participant died; or

(ii) December 31 of the calendar year in which the Participant would have attained age 70½, if later.

(B) If the Participant’s surviving Spouse is the Participant’s sole Beneficiary and the surviving Spouse dies after the Participant but before distributions to the surviving Spouse begin, this subsection, other than subparagraph (A) immediately above, will apply as if the surviving Spouse were the Participant.

If the Participant’s surviving Spouse is not the Participant’s sole Beneficiary, then distributions to the Beneficiary will begin by December 31 of the calendar year immediately following the calendar year in which the Participant died.

(C) If there is no Beneficiary as of September 30 of the year following the year of the Participant’s death, the Participant’s Account balance will be distributed to the Participant’s estate no later than by December 31 of the calendar year containing the fifth anniversary of the Participant’s death.

(d) Special Definitions. In addition to the terms defined in Plan section 2.1 or elsewhere in this Plan, whenever used in this Plan section, the following terms shall have the respective meanings set forth below, unless expressly provided otherwise. When the defined meaning is intended, the term is capitalized.

(1) “Distribution Calendar Year” means a calendar year for which a minimum distribution is required. For distributions beginning before the Participant’s death, the first Distribution Calendar Year is the later of (A) the calendar year during which the Participant attains age 70 ½, if the Participant is a “5‑percent owner,” as defined in Code section 416, or has incurred a Separation from Service or (B) December 31 of the calendar year in which the Participant has a Separation from Service. For distributions beginning after the Participant’s death, the first Distribution Calendar Year is the calendar year in which distributions are required to begin. The required minimum distribution for the Participant’s first Distribution Calendar Year will be made on or before the Participant’s Required Beginning Date.

(2) “Life Expectancy” means the life expectancy determined under the Single Life Table in Treasury Regulations section 1.401(a)(9)‑9.

(3) “Required Beginning Date” means the later of:

(A) The December 31 of the calendar year in which the Participant attains age 70½, if the Participant is a “5‑percent owner,” as defined in Code section 416, or has incurred a Separation from Service, and

(B) In all other cases, the December 31 of the calendar year in which the Participant has a Separation from Service.

(C) Effective August 8, 2016, “Required Beginning Date” means the later of:

(i) The April 1 of the calendar year following the calendar year in which the Participant attains age 70½, if the Participant is a “5‑percent owner,” as defined in Code section 416, or has incurred a Separation from Service, and

(ii) In all other cases, the April 1 of the calendar year following the calendar year in which the Participant has a Separation from Service.

Notwithstanding any provision of this Plan section to the contrary and consistent with Code section 401(a)(9)(H), no minimum distribution shall be required under this Plan section for the 2009 calendar year. The Required Beginning Date for any individual shall be determined without regard to the preceding sentence for purposes of applying this Plan section to required minimum distributions for any calendar year after 2009. Moreover, the fifth anniversary of the Participant’s death under Plan section 7.6(c)(2)(C) shall be determined by disregarding calendar year 2009. A Direct Rollover will be offered only for distributions that would be Eligible Rollover Distributions without regard to Code section 401(a)(9)(H), as these terms are defined in Plan section 7.7(b).

7.7 Mandatory Tax Withholding and Direct Rollovers

(a) General Rule. Notwithstanding any Plan provision to the contrary, all withdrawals and other distributions under this Plan shall comply with the requirements of this section, Code section 401(a)(31), the Treasury Regulations thereunder, and related regulatory rules. Under this section, a Distributee entitled to a current withdrawal or distribution from the Plan may elect, at the time and in the manner prescribed by the Administrative Committee, to have any portion of an Eligible Rollover Distribution paid directly to an Eligible Retirement Plan. In prescribing the manner of making elections with respect to Eligible Rollover Distributions, the Administrative Committee may provide for a uniform, nondiscriminatory application of any restrictions permitted under applicable sections of the Code, Treasury Regulations, and related regulatory rules, including a requirement that a Distributee may not elect to make a Direct Rollover from a single Eligible Rollover Distribution to more than one Eligible Retirement Plan.

(b) Special Definitions. In addition to the terms defined in Plan section 2.1 or elsewhere in this Plan, whenever used in this Plan section, the following terms shall have the respective meanings set forth below, unless expressly provided otherwise. When the defined meaning is intended, the term is capitalized.

(1) “Direct Rollover” means an Eligible Rollover Distribution that is paid directly to an Eligible Retirement Plan at the direction and for the benefit of the Distributee.

(2) “Distributee” means a Participant, a Participant’s surviving Spouse or a Participant’s Spouse who is the Alternate Payee.

Effective for distributions made after December 31, 2009 on behalf of a deceased Participant to a Beneficiary who is neither the Participant’s surviving Spouse or the Participant’s former Spouse and Alternate Payee, the non-spouse Beneficiary shall be a Distributee and the distribution will be treated as an Eligible Rollover Distribution if the following requirements are met. The distribution must made on behalf of the non-spouse Beneficiary in a direct transfer to an individual retirement account, described in Code section 408(a), or an individual retirement annuity, described in Code section 408(b) that is treated as an inherited individual retirement account or annuity for purposes of Code section 408(d)(3)(C). In addition, Code section 401(a)(9)(B), other than clause (iv) thereof relating to required minimum distributions to the Beneficiary, shall apply to the inherited individual retirement account or annuity.

(3) “Eligible Retirement Plan” is an individual retirement account described in Code section 408(a), an individual retirement annuity described in Code section 408(b) (other than an endowment contract), an annuity plan described in Code section 403(a), a qualified trust described in Code section 401(a) that accepts the Distributee’s Eligible Rollover Distribution, an annuity contract described in Code section 403(b); an eligible deferred compensation plan under Code section 457(b) which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state and which agrees to separately account for amounts transferred into such plan from this Plan; and a Roth IRA described in Code section 408A(b).

(4) “Eligible Rollover Distribution” means any distribution of all or any portion of the balance to the credit of the Distributee, except that an Eligible Rollover Distribution does not include:

(A) Any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the Distributee and the Distributee’s designated Beneficiary, or for a specified period of ten years or more;

(B) Any distribution to the extent the distribution is required under Code section 401(a)(9) and related Treasury Regulations;

(C) Any loan that is treated as a deemed distribution pursuant to Code section 72(p);

(D) Any dividends paid on employer securities and passed through to the Participant, Alternate Payee or Beneficiary, as described in Code section 404(k);

(E) A distribution that is a permissible withdrawal from an eligible automatic contribution arrangement within the meaning of section 414(w); and

(F) The portion of any distribution shall not fail to be an Eligible Rollover Distribution merely because such portion consists of After-Tax Contributions, which are not includable in gross income, if such portion is transferred to an individual retirement account or annuity described in Code section 408(a) or (b), to a qualified plan described in Code section 401(a) or 403(a), or to an annuity contract described in Code section 403(b) that agrees to separately account for amounts so transferred, including separately accounting for the portion of such distribution which is includable in gross income and the portion of such distribution which is not so includable. The portion of any distribution from a designated Roth account under the Plan shall not fail to be an Eligible Rollover Distribution if such portion is transferred to another Roth account under an applicable retirement plan described in Code section 402A(e)(1) or a Roth IRA described in Code section 408A.

Determinations of what constitutes an Eligible Rollover Distribution shall at all times be made in accordance with the current rules under Code section 402(c), which shall be controlling for this purpose.

(G) “Conversion” means a Direct Rollover of an Eligible Rollover Distribution from the Plan to the Roth IRA, within the meaning of Code section 408A. The amount rolled over is included in the gross income of the Distributee to the same extent that such amount would have been included in gross income if not rolled over. A Conversion is not subject to mandatory income tax withholding under Code section 3405. A Distributee may elect a Conversion of an Eligible Rollover Distribution made on or after January 1, 2008.

7.8 In-Plan Roth Rollovers

(a) Participant Eligibility. A Participant may elect to roll over a distribution to an In-Plan Roth Rollover Account in accordance with the provisions of this section 7.8. A Participant may elect to rollover amounts held in the accounts described below in Plan section 7.8(b) without regard to whether the Participant satisfies the requirements for distribution in accordance with this Article VII. In-Plan Roth Rollover Contributions shall be subject to the same Plan rules as Roth Contributions. The Plan Administrator will maintain such records as are necessary for the proper reporting of In-Plan Roth Rollover Contributions and will administer the In-Plan Roth Rollover Account in accordance with Code section 402A and the regulations promulgated thereunder.

(b) Permitted Sources. The following contributions are permitted for roll over to the In-Plan Roth Rollover Account:

(1) After-Tax Account,

(2) After-Tax Rollover Account,

(3) Matching Account,

(4) Pre-Tax Account,

(5) Rollover Account, and

(6) SIP Accounts noted in Appendix H.1.

(c) Participant’s Spouse. Solely for the purposes of determining eligibility for an In-Plan Roth Rollover Contribution, the Plan will treat a Participant’s surviving Spouse, former Spouse or Alternate Payee Spouse as a Participant. A non-spouse beneficiary may not make an In-Plan Roth Rollover Contribution to the Plan.

(d) Form of Rollover. An In-Plan Roth Rollover Contribution must be made by the Participant in the form of a direct rollover. An In-Plan Roth Rollover Contribution may not include Plan loans.

(e) Distributions. The distribution provisions in Plan section 7.1 will apply to In-Plan Roth Rollover Contributions.

(f) Treatment of In-Plan Roth Rollover Contributions. Notwithstanding any other provision of the Plan to the contrary, an In-Plan Roth Rollover Contribution is not a Rollover or Roth Rollover Contribution for purposes of the Plan. Except for amounts withheld pursuant to a voluntary withholding election, an In-Plan Roth Rollover Contribution will not be treated as a distribution for purposes of sections 72(p), 401(a)(11), or 411(d)(6)(B)(ii) of the Code. Amounts in a Participant’s In-Plan Roth Rollover Account may only be withdrawn by a Participant when the Participant is eligible for a distribution from the Plan under Article VII.

7.9 Hurricane Harvey Relief

(a) Hardship Withdrawal. A Participant who qualifies as a Hurricane Harvey Individual (as defined in Plan section 7.9(b)(i) below) may elect to withdraw amounts as follows on or after August 23, 2017 and before January 31, 2018 if he or she can demonstrate the existence of a financial hardship, as defined below:

(1) Withdrawal Sources. A Hurricane Harvey hardship withdrawal under this section 7.9 will be made from the Participant’s Pre-Tax Account and Roth Account, excluding the portion attributable to any income or pledged as security for a loan, and in all cases not in excess of the amount of the financial hardship.

(2) Financial Hardship. A “financial hardship” is the existence of an immediate and heavy financial need which cannot reasonably be met by other resources available to the Hurricane Harvey Individual. A distribution hereunder is automatically treated as being made on account of an immediate and heavy financial need if it is for any Hurricane Harvey-related hardship (which may include expenses for food, shelter and clothing).

(3) Deferral Suspension. A Participant’s Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions and After-Tax Contributions will not be subject to a six-month suspension when taking a distribution under this section 7.9.

(4) Documentation. Application shall be made on such forms and under such requirements as the Administrative Committee (or its delegee) prescribes. Requirements for supporting documentation will be waived at the time of the request for a hardship withdrawal if documentation is unavailable; however, the Participant will be asked to provide supporting documentation as soon as feasible.

(5) Distribution. Once the Administrative Committee (or is delegee) has approved the Participant’s request for a withdrawal, the amount to be withdrawn will be based on the vested amounts in the Participant’s Account eligible for withdrawal as set forth in Plan section 7.9(a)(1) above in a lump sum.

(b) Definitions.

(1) “Hurricane Harvey Individual” means a Participant whose principal residence; parent, grandparent, child or grandchild’s principal residence; place of employment; or parent, grandparent, child or grandchild’s place of employment was located in the Hurricane Harvey Disaster Area. The Committee will accept the Participant’s representation that she or he constitutes a Hurricane Harvey Individual, unless the Administrative Committee (or its delegee) has actual knowledge to the contrary.

(2) “Hurricane Harvey Disaster Area” means an area with respect to which a major disaster has been declared by the President of the United States before September 21, 2017, under section 401 of The Robert T. Stafford Disaster Relief and Emergency Assistance Act, Public Law 93-288, as amended (codified at 42 U.S.C §§ 5121-5207) by reason of Hurricane Harvey.

Article 8.Participant Loans

8.1 Availability of Loans

The Administrative Committee, in accordance with the following, may make loans to Participants who are Active Participants or Inactive Participants (referred to for purposes of this section as “Participants”) from the vested portion of the Participant’s Account. Loans shall (a) be made available on a reasonably equivalent basis, (b) not be made available to Highly Compensated Employees in an amount equal to a greater percentage of their vested Account balance or the percent made available to other loan applicants, (c) bear a reasonable rate of interest, and (d) be adequately secured by the Participant’s vested Account balance.

8.2 Amount of Loan

No loan (when added to the outstanding balance of all other loans made by the Plan to the Participant) shall exceed the lesser of:

(a) Fifty percent of the Participant’s vested Account, or

(b) Fifty thousand dollars, reduced by the highest outstanding balance of his or her loans from the Plan during the one year period ending on the date the loan is made over the outstanding balance of all of his or her Plan loans on the date on which such loan was made.

For the purpose of this limitation, all loans from all plans of the Employer are aggregated.

8.3 Procedures for Loans

The Administrative Committee shall promulgate written loan procedures which shall form part of the Plan which may include, but need not be limited to, the following information:

(a) The identity of the persons or positions authorized to administer the loan program.

(b)    The procedure for applying for loans.

(c)    The basis on which loans will be approved or denied.

(d)    The limitations, if any, on the types and amount of loans offered.

(e)    The procedure under the program for determining a reasonable rate of interest.

(f)    The types of collateral which may secure a Participant’s loan.

(g) The events constituting default and the steps that will be taken to preserve Plan assets in the event of such default.

In the event of any conflict between the loan procedures and the provisions of this section, the loan procedures shall control.

Article 9. Investment Elections

9.1 Investment of Contributions

All Pre-Tax Deferrals, Roth Contributions, After‑Tax Contributions, Adjustment Contributions, Catch‑Up Contributions, Rollover Contributions, Roth Rollover Contributions, After-Tax Rollover Contributions, In-Plan Roth Rollover Contributions and loan repayments (both principal and interest) made by and on behalf of a Participant each Plan Year and amounts merged into the Plan shall be invested as the Participant shall designate in the Investment Funds then available in increments of 1 percent of the aggregate amount of such contributions. Participants may invest up to 30% of future Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions, In-Plan Roth Rollover Contributions and After-Tax Contributions in the Oxy Stock Fund, but no new Rollover Contributions or Roth Rollover Contributions may be invested in the Oxy Stock Fund. Notwithstanding any provision to the contrary, a Participant may not transfer any investment into the Oxy Stock Fund if the amount a Participant holds under the Oxy Stock Fund exceeds 30% of the Participant’s total Plan balance.

Each Participant may make the designation described above by making an election in accordance with procedures established by the Administrative Committee upon becoming a Participant and may change such election at any time by making another election in accordance with procedures established by the Administrative Committee. Any such election shall take effect as of the first available pay period after the election was received by the Administrative Committee.

The selection of any Investment Fund is the sole and exclusive responsibility of each Participant, and it is intended that the selection of an Investment Fund by each Participant be within the parameters of section 404(c) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) and the regulations thereunder. Neither the Employer, Administrative Committee, Investment Committee nor any of the directors, officers, agents or Employees of the Employer are empowered to or shall be permitted to advise a Participant as to the manner in which his Accounts shall be invested or changed. No liability whatsoever shall be imposed upon the Employer, the Trustees, any Committee member, or any director, officer, agent or Employee of the Employer for any loss resulting to a Participant’s account because of any sale or investment directed by a Participant under this section or because of the Participant’s failure to take any action regarding an investment acquired pursuant to such elective investment.

In the event that a Participant fails, or continues to fail, to designate the Investment Fund in which Pre-Tax Deferrals, Roth Contributions, After‑Tax Contributions, Adjustment Contributions, Catch‑Up Contributions, Rollover Contributions, Roth Rollover Contributions, After-Tax Rollover Contributions, In-Plan Roth Rollover Contributions, loan repayments, or amounts merged into the Plan that are to be invested, such amounts shall be invested in the default Investment Fund, which shall be the target date fund offered as an Investment Fund under the Plan that applies to the Participant based on the year the Participant will attain age 65, or such other Investment Fund designated by the Investment Committee as the default Investment Fund.

Any amount previously defaulted into a default Investment Fund due to a Participant’s failure to designate an Investment Fund shall not be re-designated or transferred, unless the Participant otherwise transfers such amount in accordance with Plan section 9.2(a). The default Investment Fund described above is the Plan’s qualified investment alternative, as this term is defined in Department of Labor Regulations section 2550.404c‑5(e).

Matching Contributions made on behalf of a Participant shall be invested in the Oxy Stock Fund.

1Section 

9.2 Transfers of Existing Balances

(a) General Rules. Subject to any investment limitation or restriction imposed by the Investment Fund and except as provided in Plan section 9.5, each Participant, including Inactive Participants and Former Participants, as well as each Alternate Payee or spousal Beneficiary with an Account under the Plan may elect to transfer, in accordance with procedures established by the Administrative Committee, amounts invested in any Investment Fund to one or more Investment Funds then available in increments of 1 percent of the amount being transferred. If the election is received by the Administrative Committee by 4 p.m. (Central Time) on an Accounting Date, the transfer will be processed on that Accounting Date. Each election made under this Plan section shall be effective as of the first Accounting Date after the date in which notice thereof is received by the Administrative Committee. If the election is received by the Administrative Committee after 4 p.m. (Central Time) or on a date other than an Accounting Date, the transfer will be processed on the next Accounting Date. The Administrative Committee may impose such Investment Fund transfer fees as it deems reasonable and appropriate to defray the administrative expenses of the Plan. Any transfer of existing balances made under this Plan section does not affect the investment of future contributions, including loan repayments and amounts merged into this Plan, which will be invested as provided under Plan section 9.1 and the last investment election of the Participant filed thereunder.

(b) Oxy Stock Fund Transfers. A vested Participant may not transfer any investment into the Oxy Stock Fund if the amount a Participant holds under the Oxy Stock Fund exceeds 30% of the Participant’s total Plan balance.

(c) Qualified Plan Transfers. Nothing contained in this Plan section shall be construed as preventing a Participant, including Inactive Participants and Former Participants, from having amounts allocated to his or her Account in any Investment Fund transferred to one or more other Investment Funds for the purpose of facilitating an asset transfer to the trustee of a Qualified Plan sponsored by a purchaser or the subsidiary of a purchaser as a result of a transaction involving the sale by the Company or an Affiliate of either all or substantially all of the outstanding common stock of an Affiliate or all or substantially all of the assets of a facility, under circumstances where the Participant or Inactive Participant is employed by the Affiliate or at the facility that is the subject of the sale.

9.3 Transfer of Assets

The Administrative Committee shall direct the Trustee to transfer monies or other property between Investment Funds as soon as is practicable after each Accounting Date to the extent required to carry out the aggregate contribution and transfer transactions as of such Accounting Date after the necessary entries have been made in the Accounts and offsetting transfer elections have been reconciled, in accordance with uniform rules established by the Administrative Committee.

9.4 Reserved

9.5 Matching Account Diversification Rights After August 1, 2004

This section is effective August 2, 2004 and shall apply notwithstanding any contrary provision of this Plan.

(a) Diversification Elections After August 1, 2004. A Qualified Participant shall have the right to transfer to other available Investment Funds, in accordance with Plan section 9.2, up to 100 percent of the current market value of the number of Units in the Oxy Stock Fund credited to his Matching Account.

(b) No Reinvestment. For the period from July 1, 2006 through March 30, 2007, the number of Units in a Qualified Participant’s Matching Account that have been transferred out of the Oxy Stock Fund as described in subsection (a) above may not be reinvested the Oxy Stock Fund.

(c) Election Procedures. Elections to transfer amounts from the Oxy Stock Fund among available Investment Funds shall be made pursuant to procedures established by the Administrative Committee. Each election made under this section shall be effective as of the first Accounting Date after the date on which the Administrative Committee properly receives the election.

(d) Authority. The Investment Committee shall have the authority to take any actions as may be appropriate or necessary to ensure the proper operation of the Plan and investment in the Oxy Stock Fund consistent with the provisions of this section.

(e) Qualified Participant. For purposes of this section, a “Qualified Participant” means:

(1) Effective August 2, 2004, a Participant, who has completed at least 10 years of Service under the Plan and has attained age 55;

(2) Effective January 1, 2005, a Participant, who has completed at least 10 years of Service under the Plan and has attained age 50;

(3) Effective March 1, 2005, a Participant, who has completed at least 5 years of Service under the Plan and has attained age 50;

(4) Effective July 1, 2006, a Participant, who has completed at least 5 years of Service under the Plan; and

(5) Effective January 1, 2007, a Participant, who has completed at least 3 years of Service under the Plan.

(6) Effective January 1, 2015, any Active Participant, regardless of the individual’s years of Service under the Plan.

2Section 

Until July 1, 2006, the Service requirement described in paragraphs (1) through (4) must be met on or before a Participant incurs a Separation from Service. As of July 1, 2006, a Qualified Participant includes a Former Participant who has incurred a Separation from Service but only with respect to the portion of the vested portion of the Participant’s Matching Account as of his Separation from Service.

Article 10. Participant Accounts and Records of the Plan

10.1 Accounts and Records

The Participant’s Pre-Tax Account, Roth Account, Matching Account, After‑Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account shall be assigned a subaccount for each Investment Fund in which the Account is invested. Each such subaccount shall be maintained and valued separately from all other subaccounts. The Administrative Committee shall maintain records relative to a Participant’s Accounts so that there may be determined as of any Accounting Date the current market value of his Accounts in the Trust Fund.

Each Participant, Alternate Payee and Beneficiary with an Account shall be advised from time to time, at least once each Plan Year, as to the value of his or her Account and the portions thereof attributable to his or her Matching Account and the sum of his or her Pre-Tax Account, Roth Account, Matching Account, After‑Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account and to the various Investment Funds.

10.2 Account Value

As of any given date for which determination of the value of an Account is required, such value shall equal the sum of the value of Pre-Tax Account, Roth Account, Matching Account, After‑Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account as of the preceding Accounting Date plus any additional contributions withheld or paid and less the amount of any withdrawals from such Account after the Accounting Date and prior to the date of determination.

10.3 Investment Funds

The Trust Fund shall consist of the Investment Funds, and each Account invested in an Investment Fund shall have an undivided proportionate interest in that Investment Fund. The Investment Committee shall have the right to determine the number of Investment Funds to be maintained by the Plan, and to increase or decrease that number from time to time as it deems appropriate. The Investment Committee shall establish additional Investment Funds or eliminate existing Investment Funds. In so doing, the Investment Committee shall implement and carry out investment objectives and policies which it shall establish and maintain.

10.4 Unit Value of Investment Funds

As of each Accounting Date, the Trustee shall determine the fair market value of the assets of each Investment Fund, and shall notify the Administrative Committee of the value so determined. Assets for which there is a readily ascertainable market shall be valued by the Trustee at their fair market value, determined by the last known public sale on the Accounting Date as of which the market value is determined. In the absence of a sale on the Accounting Date, the fair market value of such assets, as well as other assets for which there is no readily ascertainable fair market value, shall be determined by the Trustee in such consistent manner as the Trustee shall consider appropriate.

10.5 Calculation of Unit Value

The Trustee shall divide the aggregate value of the assets of each Investment Fund, as so determined, by the total number of outstanding Units in such Investment Fund on the Accounting Date. The result obtained shall be the new value of each Unit, or “Unit value,” as of the Accounting Date. The Unit value for all Investment Funds shall be ten dollars on the first Accounting Date in 1999.

10.6 Valuation Adjustments

As of each Accounting Date, after the Units in each Investment Fund have been revalued, the Administrative Committee shall adjust the balances in the Accounts in the respective Investment Funds of the Trust Fund, upward or downward, in proportion to the Account balance in the Investment Fund as of the previous Accounting Date. As a result, the sum of such Account balances will equal the net value of each Investment Fund of the Trust Fund as of that Accounting Date. The subaccounts shall then, when appropriate, be credited with additional Units by dividing the dollar amount of contributions, fund transfers, loan repayments, and dividends paid with respect to Oxy Stock to be allocated to each subaccount on that Accounting Date by the newly calculated value of a Unit in the Investment Fund.

3Section 

10.7 Debiting of Accounts upon Distribution, Withdrawal, Loan or Charge

Any Units distributed or withdrawn from an Account (including any Units debited as a result of an Investment Fund transfer fee or redemption fee imposed pursuant to Plan section 9.2) shall be charged to the respective subaccounts in each Investment Fund as of the date the benefit or charge is payable. The amount distributable or chargeable to the Account shall be equal to the number of Units distributed or charged from the Account multiplied by the Unit value determined as of the Accounting Date immediately preceding the date as of which the distribution or charge is payable.

10.8 Unit Value upon Transfer of Investment Funds

Participants, Alternate Payees and Beneficiaries electing to transfer from one Investment Fund to another under Plan section 9.2 shall, as of the Accounting Date of the transfer, have their Accounts in the Investment Fund from which the transfer is made charged and their Accounts in the Investment Fund to which the transfer is made credited, based upon the applicable Investment Fund Unit values in effect as of the Accounting Date.

10.9 Oxy Stock Fund Valuation

The balance of each Matching Account and, separately, any other portion of the Account invested in the Oxy Stock Fund shall be maintained in full and fractional Units.

All Oxy Stock acquired by the Oxy Stock Fund, including, but not by way of limitation, Oxy Stock contributed directly by the Employer or purchased with the contributions, Oxy Stock purchased with cash dividends paid in respect of Oxy Stock, Oxy Stock acquired from stock dividends and stock splits, and Oxy Stock purchased with the proceeds of the sale or exchange of warrants, rights or dividends in kind distributed in respect of Oxy Stock, shall be allocated to the Accounts based on the portion of the Account invested in the Oxy Stock Fund as of the Accounting Date in which the Oxy Stock is acquired.

For the purpose of valuing an Account in connection with any withdrawal or loan under the provisions of the Plan or for the purpose of any distribution in kind or partly in kind, shares of Oxy Stock shall be valued as of the Accounting Date of the withdrawal, loan, or distribution based on the closing quotation on the New York Stock Exchange on the Accounting Date in which such withdrawal, loan, or distribution is made; provided, however, that if shares of Oxy Stock are sold in connection with such a withdrawal, loan, or distribution, the shares sold shall be valued at the net proceeds received from such sale. If the closing price of such Oxy Stock shall not be so quoted or if so quoted shall not be available to the Administrative Committee, a composite index price or other price which shall be generally accepted for the establishment of fair market value shall be used for the purpose of so valuing the Account.

For the purpose of valuing an Account in connection with any transfer under the provisions of the Plan, shares of Oxy Stock shall be valued as of the effective date of the transfer based on the closing quotation on the New York Stock Exchange on the Accounting Date in which such transfer is made; provided, however, that if shares of Oxy Stock are sold in connection with such transfer, the shares sold shall be valued at the net proceeds received from such sale. If the closing price of such Oxy Stock shall not be so quoted or if so quoted shall not be available to the Administrative Committee, a composite index price or other price which shall be generally accepted for the establishment of fair market value shall be used for the purpose of so valuing the Account.

10.10 Value of Accounts

The value of the balance of any Account as of any Accounting Date shall equal:

(a) The number of Units credited to the Account as of that date, including Units credited on that date pursuant to Plan section 10.6, multiplied by the Unit value determined as of the Accounting Date, plus

(b) Any uninvested cash in the Account.

10.11 Cost Account

The Trustee shall maintain records so that the cost or “basis” (for tax purposes) of the Oxy Stock allocated to an Account may be determined as of any Accounting Date. Whenever shares of Oxy Stock are distributed from the Account, such shares shall be assigned a cost equal to the average cost of all shares allocated at the same time in accordance with rules and procedures adopted for the purpose by the Administrative Committee.

10.12 Rollover and Roth Rollover Contributions

(a) Subject to the Administrative Committee’s approval and in accordance with uniform and nondiscriminatory procedures adopted by the Administrative Committee, Active or Inactive Participants may contribute, under the conditions specified in this Plan section, to this Plan any of the amounts specified as Rollover Contributions, Roth Rollover Contributions or, on and after January 1, 2020, After-Tax Rollover Contributions. Rollover Contributions will be held in the Participant’s Rollover Account. Roth Rollover Contributions will be held in the Participant’s Roth Rollover Account. After-Tax Rollover Contributions will be held in the Participant’s After-Tax Rollover Account.

(b) The amount must have been received by or on behalf of the Participant as an eligible rollover distribution, as defined in Code section 402(c)(4).

(1) In the case of direct rollovers, the distribution must be received directly from:

(A) A Qualified Plan;

(B) A qualified plan described in Code section 403(a);

(C) An annuity contract described in Code section 403(b);

(D) An eligible plan under Code section 457(b) which is maintained by a state, a political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state; or

(E) A Roth IRA described in Code section 408A(b).

(2) In the case of a Rollover Contribution or Roth Rollover Contribution by the Participant, as opposed to a direct rollover, the Participant must have received the distribution no more than 60 days (unless the 60‑day rollover deadline has been waived by the Internal Revenue Service pursuant to Code section 402(c)(3), or the Participant makes a written certification to the Plan that satisfies section 3.02 of Revenue Procedure 2016-47) earlier from:

(A) A plan described in paragraph (1), except that any Roth amounts must be received as a direct rollover, or

(B) An individual retirement account or annuity described in Code section 408(a) or 408(b) that only includes amounts contributed to such account or annuity that had been rollover contributions from a plan described in paragraph (1).

(3) On a uniform and nondiscriminatory basis, the Administrative Committee or the Company may permit direct rollovers of promissory notes in connection with a loan under a Qualified Plan pursuant to Treasury Regulations section 1.401(a)(31)–1, Q&A–16. The Administrative Committee may establish such reasonable procedures as it deems necessary to facilitate the direct rollover of the promissory notes and to ensure that after the rollover, each loan under the Plan complies with Code section 72(p), ERISA section 408(b)(1), and the regulations thereunder. By way of illustration and not limitation, the Administrative Committee may reamortize directly rolled over loans to accommodate repayment of the loans in conjunction with the payroll schedules of an Employer so as to comply with the maximum permitted term of the loan, or may require a Participant to execute such modification to an existing loan that is rolled over, as the Administrative Committee deems, in its sole discretion, necessary to comply with Code section 72(p), ERISA section 408(b)(1), or the regulations thereunder.

(c) Before accepting an amount as a Rollover, Roth Rollover or After-Tax Rollover Contribution, the Administrative Committee may require such information and documents it deems necessary or appropriate to establish that the contribution will satisfy the requirements of this Plan section and that receipt of the contribution will not adversely affect the qualified status of this Plan. To the extent deemed necessary or appropriate by the Administrative Committee, such information may include copies of one or more of the following: IRS Form 1099, a distribution statement, the distribution check, certifications from the Participant, and statements from the administrator of the transferor plan that such plan had received a favorable determination letter from the Internal Revenue Service.

(d) Rollover, Roth Rollover and After-Tax Rollover Contributions, other than a promissory note evidencing a Participant loan that is rolled over, shall be invested in such Investment Funds as the Participant shall select, in accordance with such rules as are provided in Article 9, or in accordance with other procedures approved by the Administrative Committee. Rollover, Roth Rollover and After-Tax Rollover Contributions to this Plan will not be accepted unless the Participant has made an affirmative investment election with respect to his or her Rollover, Roth Rollover or After-Tax Rollover Account under Article 9. Notwithstanding the foregoing, in no event shall Rollover, Roth Rollover or After-Tax Rollover Contributions be invested in the Oxy Stock Fund.

(e) If a Rollover, Roth Rollover or After-Tax Rollover Contribution is made to this Plan and the Administrative Committee later determines that the contribution did not satisfy the requirements of this Plan section, then the Rollover, Roth Rollover or After-Tax Rollover Contribution, plus any earnings attributable to the Rollover, Roth Rollover or After-Tax Rollover Contribution, shall be distributed to the Participant, within a reasonable time after the Administrative Committee’s determination. The Administrative Committee may use any reasonable method to determine the amount of earnings attributable to the Rollover, Roth Rollover or After-Tax Rollover Contribution.

(f) The balance in a Participant’s Rollover, Roth Rollover or After-Tax Rollover Account shall be distributed at the same time and in the same manner as other amounts in the Participant’s Account. Any questions concerning entitlement to a distribution of a Rollover, Roth Rollover or After-Tax Rollover Account shall be resolved by adding the term “and Rollover, Roth Rollover or After-Tax Rollover Account” in each place where the term “Account” appears in Article 7.

10.13 Merger of the THUMS Long Beach Company Savings and Investment Plan

Effective as of October 31, 2011, the THUMS Long Beach Company Savings and Investment Plan is merged with and into this Plan. The entire interest of each individual, who was a participant in the THUMS Long Beach Company Savings and Investment Plan on October 28, 2011, shall be transferred to this Plan and Appendix H shall control the treatment of such interest as stated therein.

Article 11. Financing

11.1 Trust Fund

The Company shall maintain a trust to finance the benefits under the Plan, by entering into one or more Trust Agreements or insurance contracts approved by the Company, or by causing insurance contracts to be held under a Trust Agreement. Any Trust Agreement is designated as and shall constitute a part of this Plan, and all rights which may accrue to any person under this Plan shall be subject to all the terms and provisions of such Trust Agreement. A Trustee shall be appointed by the Board and shall have such powers as provided in the Trust Agreement. The Company may modify any Trust Agreement or insurance contract from time to time to accomplish the purposes of the Plan and may replace any insurance company or appoint a successor Trustee or Trustees. By entering into such Trust Agreements or insurance contracts, the Company shall vest in the Trustee, or in one or more investment managers (as defined under ERISA) appointed under the terms of the Trust Agreement from time to time by action of the Investment Committee, responsibility for the management and control of the Trust Fund. In the event the Investment Committee appoints any such investment manager, the Trustee shall not be liable for the acts or omissions of the investment manager or have any responsibility to invest or otherwise manage any portion of the Trust Fund subject to the management and control of the investment manager. The Investment Committee from time to time shall establish a funding policy which is consistent with the objectives of the Plan and shall communicate it to the Trustee and each investment manager so that they may coordinate investment policies with such funding policy.

11.2 Oxy Stock Fund

(a) General Rules. The Oxy Stock Fund shall consist of shares of Oxy Stock and cash or cash equivalents that are held pending investment in Oxy Stock. Investment in such shares shall be made from time to time by a direct issue of Oxy Stock from the Company or by purchase from securities dealers or by private purchase at such prices and in such amounts as the Trustee may determine in its absolute and complete discretion. However, no private purchase of such shares shall be made at a total cost greater than the total cost (including brokers’ fees and other expenses of purchase) of purchasing such shares at the then prevailing price of such shares on the open market, such prevailing price to be determined by the Trustee as nearly as practicable based on the most recent public trading prices for the Oxy Stock. The Trustee may match purchases and sales to satisfy investment elections, withdrawals, loans and distributions of Participants.

The Trustee in its discretion may limit the daily volume of its purchases or sales of Oxy Stock to safeguard interest of Participants or comply with legal or exchange requirements. If the Trustee limits daily volume then the purchase prices or sale proceeds, as the case may be, during the period of volume limitations, shall be averaged, and the average per share price or sale proceeds shall be used in determining the cost or proceeds to be applied in satisfaction of any order of a Participant which requires the Trustee to purchase or sell Oxy Stock during such period.

All Oxy Stock purchased by the Trustee shall be registered in the name of the Trustee or its nominee, and legal title to such Oxy Stock shall remain in the Trustee until the Participant shall become entitled to distribution thereof pursuant to this Plan.

The Trustee in its own discretion may invest funds awaiting investment in Oxy Stock in short‑term obligations, including obligations of the United States of America or any agency or instrumentality thereof, trust and participation certificates, beneficial interests in any trust, and such other short‑term obligations as the Trustee deems to be appropriate for such interim investment purposes.

In the event any option, right or warrant is received by the Trustee on Oxy Stock, the Trustee shall sell the same at public or private sale and at such price and upon such other terms as it may determine, unless the Investment Committee shall determine that such option, right or warrant should be exercised, in which case the Trustee shall exercise the same upon such terms and conditions as the Investment Committee may prescribe.

(b) Election Restrictions for Officers. Investment elections of Company officers shall be limited, if necessary, so that the beneficial interest in the Oxy Stock held by the Trust Fund for their Accounts shall not exceed, in the aggregate, 20 percent of the total value of all securities and other assets held by the Trust Fund in all Investment Funds. For purposes of this section, the term “officers” shall have the same meaning as set forth in Regulations section 240.3‑b‑2 promulgated pursuant to section 3(b) of the Securities Exchange Act of 1934.

(c) Voting Rights. Before each annual or special meeting of the shareholders of the Company, and at such other times when shareholder action is required, the Company or Trustee (as determined under the applicable Trust Agreement) shall send to each Participant, Beneficiary and Alternate Payee who has an investment in Oxy Stock through the Oxy Stock Fund, the proxy or consent solicitation materials that are sent to the Company’s shareholders of record. Each such Participant, Beneficiary and Alternate Payee shall have the right to instruct the Trustee confidentially as to the method of voting the shares of Oxy Stock allocated to the Account (through investment in the Oxy Stock Fund) as of the record date for determining the shares that are entitled to vote at the meeting of shareholders or that are entitled to give or withhold consent to corporate action. The Trustee in accordance with the instructions received from the Participant, Beneficiary, or Alternate Payee shall vote such full and fractional shares of Oxy Stock. The Administrative Committee shall instruct the Trustee as to the method of voting shares of Oxy Stock for which timely voting instructions are not received from Participants, Beneficiaries or Alternate Payees. The Trustee shall not vote shares of Oxy Stock for which it does not receive voting instructions from Participants, Beneficiaries, Alternate Payees or the Administrative Committee. The Company shall ensure that the requisite voting forms, together with all information distributed to shareholders regarding the exercise of voting rights, are furnished to the Trustee and by the Trustee to such Participants, Beneficiaries and Alternate Payees within a reasonable time before such voting rights are to be exercised with respect to Oxy Stock held in the Oxy Stock Fund.

(d) Distribution or Reinvestment of Cash Dividends. In accordance with procedures set forth in this subsection, as implemented by the Administrative Committee, each Participant who is a Participant in the ESOP portion of this Plan may make the dividend pass‑through election described in this subsection with respect to dividends paid on or after June 1, 2002 on Oxy Stock held in the Oxy Stock Fund attributable to the Participant’s Matching Account and with respect to dividends paid on or after July 19, 2007 on all Oxy Stock held in the Oxy Stock Fund. The dividends on which the dividend pass‑through election may be made are referred to as Eligible Dividends. Cash dividends that are not Eligible Dividends and cash proceeds from any other distribution received on Oxy Stock shall be invested in Oxy Stock.

(1) Pass‑Through Election. With respect to Eligible Dividends, the Participant may elect between:

(A) Either:

(i) The cash payment of Eligible Dividends directly to the Participant; except, effective August 8, 2016, if the amount of Eligible Dividends is less than $10.00, then the Eligible Dividends will be reinvested pursuant to Subsection (B) below; or

(ii) If permitted by the Administrative Committee, the payment of Eligible Dividends to the Participant’s Matching Account, Pre-Tax Account, Roth Account, After-Tax Account, Rollover Account, Roth Rollover Account, After-Tax Rollover Account and In-Plan Roth Rollover Account (based on the subaccount from which the Eligible Dividend is derived) followed by the distribution of Eligible Dividends in cash to the Participant not later than 90 days after the close of the Plan Year in which the Eligible Dividends were paid by the Company; and

(B) The payment of Eligible Dividends to the Participant’s Matching Account, Pre-Tax Account, Roth Account, After-Tax Account, Rollover Account, Roth Rollover Account , After-Tax Rollover Account and In-Plan Roth Rollover Account (based on the subaccount from which the Eligible Dividend is derived) and reinvestment in Oxy Stock through the Oxy Stock Fund.

If the Participant does not make an affirmative election, he shall be deemed to have elected the reinvestment of Eligible Dividends pursuant to subparagraph (B). Any earnings on Eligible Dividends shall not be distributed pursuant to subparagraph (A)(ii), but any losses on such Eligible Dividends shall reduce the amount that can be distributed to the Participant under such provision. The Participant’s election in effect on the ex‑dividend date for the Eligible Dividend shall control. A Participant may not split his election between subparagraph (A) and subparagraph (B) with respect to any single Eligible Dividend payment date.

(2) Election Requirements. The dividend pass‑through election shall meet the following minimum requirements:

(A) A Participant must be given a reasonable opportunity before Eligible Dividends are paid or distributed in which to make the election.

(B) A Participant must have a reasonable opportunity to change a dividend election at least annually.

(C) If there is a change in the Plan terms governing the manner in which Eligible Dividends are paid or distributed, a Participant must be given a reasonable opportunity to make an election under the new Plan terms prior to the date on which the first Eligible Dividend subject to the new Plan terms is paid or distributed.

(D) No election shall be applied retroactively; elections shall apply only to future dividend allocations.

(3) Treatment of Eligible Dividends. Eligible Dividends shall be treated as follows for purposes of the Plan:

(A) A Participant shall at all times be fully vested in any Eligible Dividends with respect to which the Participant is offered a dividend pass‑through election. The Participant shall be fully vested regardless of whether the Eligible Dividends are paid in cash or reinvested in Oxy Stock allocated to the Participant’s Account and regardless of whether the Participant is vested or nonvested in other amounts held in his Matching Account.

(B) Eligible Dividends, whether paid in cash to the Participant or reinvested in the Plan, do not constitute an Annual Addition. In addition, reinvested Eligible Dividends do not constitute elective deferrals, within the meaning of Code section 402(g)(3), and shall not be treated as Pre-Tax Deferrals, Roth Contributions or other elective deferrals, under the ADP Test, or After‑Tax Contributions, Adjustment Contributions or Matching Contributions under the ACP Test.

(C) Eligible Dividends that are reinvested in Oxy Stock pursuant to a Participant’s election under this subsection are treated as earnings in the same manner as dividends with respect to which a Participant is not provided a dividend pass‑through election.

(D) Eligible Dividends paid in cash pursuant to a Participant’s election under this subsection:

(i) Are not subject to the consent requirements of Code section 411(a)(11) or the restrictions on the distributions of elective deferrals under Code section 401(k)(2)(B), notwithstanding any Plan provision to the contrary; and

(ii) Do not constitute an Eligible Rollover Distribution (as determined under Plan section 7.7(b)(4)), even if the dividends are distributed at the same time as amounts that do constitute an Eligible Rollover Distribution.

(4) Alternate Payees and Beneficiaries. Subject to such rules as the Administrative Committee may prescribe, Alternate Payees and Beneficiaries shall be treated as Participants for purposes of this subsection.

11.3 Forfeitures

The Administrative Committee may use forfeitures occurring in any processing period to pay the reasonable costs of administering the Plan to the maximum extent permitted by ERISA or to reduce Matching Contributions of all Employers without regard to whether the forfeitures are attributable to persons employed by any individual Employer for such processing period or future processing periods. If the amount of allocable forfeitures occurring in a processing period exceeds the amount of Employer contributions for such processing period, then the excess shall be deposited in a separate account. Effective December 1, 2016, or as soon as practicable thereafter but in no event later than December 31, 2016, such amounts will be deposited into a separate “Forfeiture Account,” invested in the Stable Value Fund, defined in Appendix B(a) of the Plan, or such other fund as determined within the discretion of the Administrative Committee, and such amounts will be considered Plan assets and allocated in lieu of Employer contributions in succeeding pay periods, used to pay the reasonable expenses of administering the Plan or allocated among Participants as additional contributions. If the Plan terminates while a balance in the Forfeiture Account exists, the balance shall be allocated to Participants per capita to the extent of the maximum amount permitted under Plan section 6.6. Forfeitures shall be used before the end of the Plan Year in which the forfeitures occurred to the extent administratively feasible.

11.4 Non‑Reversion

Anything in this Plan to the contrary notwithstanding, it shall be impossible at any time for the contributions of the Employer or any part of the Trust Fund to revert to the Company or an Affiliate or to be used for or diverted to any purpose other than the exclusive benefit of Participants or their Beneficiaries, except that:

(a) If a contribution or portion thereof is made by the Employer by a mistake of fact, upon written request to the Administrative Committee, such contribution or such portion, reduced by losses but not increased by earnings, shall be returned to the Employer within one year after the date of payment; and

(b) In the event that a deduction for any contributions made by the Employer is disallowed by the Internal Revenue Service in any Plan Year, then that portion of the Employer contribution that is not deductible shall be returned to the Employer within one year from the date of receipt of notice by the Internal Revenue Service of the disallowance of the deduction.

11.5 Direct Transfer of Assets from Plans of Acquired Entities

The Trust Agreement shall permit the direct receipt of assets which are transferred directly to the Trust Fund from the trustees of any other Qualified Plan sponsored, at the time of the applicable transaction, by entities which are the subject of purchase transactions made by the Company or an Affiliate.

11.6 Pension Expense Reimbursement Account (“PERA”)

The Administrative Committee in its discretion may decide to use revenue sharing payments (i.e., float income earned on uninvested cash and all other revenue, if any, received from the investments in the Plan (other than operating expenses paid by mutual fund shareholders generally, whether via rebates or otherwise, that are reflected in the net asset values of such mutual fund shares)) for approved ERISA expenses. Such amounts as well as Participant-paid fees (including loan initiation fees) and Plan-imposed excessive trading fees will be deposited into a separate “ERISA Account,” invested in the Stable Value Fund, defined in Appendix B(a) of the Plan, or such other fund as determined within the discretion of the Administrative Committee, and such amounts will be considered Plan assets. Amounts in the ERISA Account must be used for the direct benefit of Plan Participants, and any balances remaining in the ERISA Account at year end must be used by the end of the first quarter of the next Plan Year. Alternatively, the year-end balance must be allocated to Participant Accounts after this deadline. Approved ERISA expenses will include those reasonable, necessary and direct expenses incurred by the Plan for services provided by the Plan’s Trustee, recordkeeper or other service providers.

Article 12. Administration

12.1 The Administrative Committee

The Plan shall be administered by an Administrative Committee appointed by the Board. The Administrative Committee shall be composed of as many members as the Board may appoint from time to time, but not fewer than three members, and shall hold office at the discretion of the Board. Such members may, but need not, be Employees of the Company or any Affiliate.

Any member of the Administrative Committee may resign by delivering his or her written resignation to the Board and to the Administrative Committee Secretary. Such resignation shall be effective no earlier than the date of the written notice.

Vacancies in the Administrative Committee arising by resignation, death, removal, or otherwise, shall be filled by the Board. The Administrative Committee shall be a fiduciary under the Plan, in accordance with ERISA.

12.2 Chairperson, Secretary, and Employment of Specialists

The members of each of the Investment Committee and Administrative Committee shall elect one of their number as Chairperson and shall elect a Secretary who may, but need not, be a member of such Committee. They may authorize one or more of their number or any agent to execute or deliver any instrument or instruments on their behalf, and may employ such counsel, auditors, and other specialists and such clerical, medical, actuarial, and other services as they may require in carrying out the provisions of the Plan.

12.3 Compensation and Expenses

The members of the Investment Committee and Administrative Committee who are Employees shall serve without compensation for services as a member of such Committee. Any member of a Committee may receive reimbursement by the Company of expenses properly and actually incurred.

All expenses of administration may be paid out of the Trust Fund, to the maximum extent permitted by ERISA, unless paid by the Company. Such expenses shall include any expenses incident to the functioning of the Administrative Committee and the Investment Committee, including but not limited to, fees of accountants, counsel, and other specialists and their agents, and other costs of administering the Plan. Until paid, the expenses shall constitute a liability of the Trust Fund. However, the Company may reimburse the Trust Fund for any administration expense incurred. The Company reserves the right to charge the Accounts for reasonable expenses incurred in the administration of their Accounts. Any such charges shall be used to pay the costs of administering this Plan in the manner described in Plan section 11.3. The Company will make full disclosure of the amount and nature of any such charge prior to its imposition.

12.4 Manner of Action

A majority of the members of the Investment Committee and Administrative Committee at the time in office shall constitute a quorum for the transaction of business. All resolutions adopted, and other actions taken by a Committee at any meeting shall be by the vote of a majority of those present at any such meeting. Upon obtaining the written consent of a majority of the members at the time in office, action of a Committee may be taken otherwise than at a meeting.

12.5 Subcommittees

Each of the Investment Committee and Administrative Committee may appoint one or more subcommittees and delegate such of its power and duties as it deems desirable to any such subcommittee, in which case every reference herein made to such Committee shall be deemed to mean or include the subcommittees as to matters within their jurisdiction. The members of any such subcommittee shall consist of such officers or other Employees of the Company and such other persons as such Committee may appoint.

12.6 Other Agents

Each of the Board, the Company, the Administrative Committee and the Investment Committee may also appoint one or more persons or agents to aid it in carrying out its duties as fiduciary or nonfiduciary, and delegate such of its powers and duties as it deems desirable to such person or agents.

12.7 Records

All resolutions, proceedings, acts, and determinations of each of the Administrative Committee and the Investment Committee shall be recorded by the Secretary thereof or under the Secretary’s supervision, and all such records, together with such documents and instruments as may be necessary for the administration of the Plan, shall be preserved in the custody of the Secretary.

12.8 Rules

Subject to the limitations contained in the Plan, each of the Administrative Committee and the Investment Committee shall be empowered from time to time in its discretion to adopt by‑laws and establish rules for the conduct of its affairs and the exercise of the duties imposed upon it under the Plan.

12.9 Administrative Committee’s Powers and Duties

Except as otherwise provided in this Plan, the Company shall have responsibility for any settlor powers, functions or duties, including, without limitation, the right to amend or terminate the Plan as set forth in Plan section 13.1. The Administrative Committee shall have responsibility for the general administration of the Plan and for carrying out the Plan’s provisions. The Administrative Committee shall have such powers and duties as may be necessary to discharge its functions hereunder, including, but not limited to, the following:

(a) To construe and interpret the Plan, to supply all omissions from, correct deficiencies in and resolve ambiguities in the language of the Plan and Trust; to decide all questions of eligibility and determine the amount, manner, and time of payment of any benefits hereunder;

(b) To make a determination as to the right of any person to an allocation, and the amount thereof;

(c) To obtain from the Employees such information as shall be necessary for the proper administration of the Plan and, when appropriate, to furnish such information promptly to the Trustee or other persons entitled thereto;

(d) To prepare and distribute, in such manner as the Company determines to be appropriate, information explaining the Plan;

(e) To establish and maintain such accounts in the name of each Participant as are necessary;

(f) To instruct the Trustee with respect to the payment of benefits hereunder;

(g) To provide for any required bonding of fiduciaries and other persons who may from time to time handle Plan assets;

(h) To prepare and file any reports required by ERISA;

(i) To engage an independent public accountant to conduct such examinations and to render such opinions as may be required by ERISA;

(j) To select, engage, monitor and terminate the performance of third-party administrators and other service providers and develop policies with respect to service provider contracts to ensure that fees paid are reasonable;

(k) To allocate contributions, loan repayments and Trust Fund gains or losses to the Accounts of Participants;

(l) To take all steps it deems reasonable to correct any references or omissions that may arise in the operation of the Plan, which include taking any and all steps permitted under the Employee Plans Compliance Resolution System, the Voluntary Fiduciary Correction Program, or any other program of correction; and

(m) To designate Affiliates as Employers as described in Plan section 14.1.

12.10 Investment Responsibilities

The Investment Committee shall have the authority and responsibility to direct the Trustee with respect to the investment and management of the Trust Fund, and to establish a funding policy and method consistent with the objectives of the Plan and the requirements of ERISA. Except as otherwise provided in ERISA, the Investment Committee may delegate such authority and responsibility to direct the Trustee or any person who acknowledges in writing that it is a fiduciary with respect to the Plan and who provides the Investment Committee with a written affirmation that it is qualified to act as an investment manager within the meaning of ERISA. If the Investment Committee delegates to an investment manager the authority and responsibility to so direct the Trustee, such investment manager, and not the Investment Committee or the Trustee, shall have sole responsibility for the investment and management of so much of the Trust Fund as has been entrusted to his management and control, and, except to the extent otherwise required by ERISA, such delegation shall relieve the Investment Committee and the members thereof of all duties and responsibilities with respect to the authority and responsibility so delegated.

The Investment Committee may relinquish to the Trustee the Investment Committee’s power to direct the Trustee with respect to the investment and management of the Trust Fund. In the event the Investment Committee so relinquishes said power to the Trustee and the Trustee accepts such responsibility in writing, the Trustee shall have sole and exclusive power and responsibility with respect to the investment and management of the Trust Fund. The Investment Committee may regain the power so relinquished by appropriate Investment Committee action and notice to the Trustee.

12.11 Administrative Committee’s Decisions Conclusive

The Administrative Committee shall have the exclusive right and discretionary authority to interpret the terms and provisions of the Plan, apply the facts to the terms of the Plan, and resolve all questions arising hereunder, including the right to resolve and remedy ambiguities, inconsistencies, or omissions in the Plan, provided, however, that the construction necessary for the Plan to conform to the Code and ERISA shall in all cases control. The Administrative Committee also shall have discretionary authority to make any factual determinations under the Plan. Benefits under this Plan will be paid only if the Administrative Committee decides in its discretion that the applicant is entitled to them. The Administrative Committee shall endeavor to act in such a way as not to discriminate in favor of any class of Employees, Participants, or other persons. Any and all disputes with respect to the Plan that may arise involving Participants, Beneficiaries or Alternate Payees shall be referred to the Administrative Committee and its decisions shall be final, conclusive, and binding. All findings of fact, interpretations, determinations, and decisions of the Administrative Committee in respect of any matter or question arising under the Plan shall be final, conclusive, and binding upon all persons, including, without limitation, Employees, Participants, Beneficiaries, Alternate Payees, and any and all other persons having, or claiming to have, any interest in or under the Plan. The factual determinations and decisions of the Administrative Committee shall be given the maximum possible deference allowed by law.

12.12 Indemnity

(a) To the extent permitted by the Company’s bylaws and applicable law, the Company shall indemnify and hold harmless each of the following persons (“Indemnified Persons”) under the terms and conditions of subsection (b):

(1) Each Affiliate;

(2) Each member of the Administrative Committee

(3) Each member of the Investment Committee; and

(4) Each Employee or member of the Board who has responsibility (whether by delegation from another person, an allocation of responsibilities under the terms of this Plan document, or otherwise) for a fiduciary duty, a nonfiduciary settlor function (such as deciding whether to approve a plan amendment), or a nonfiduciary administrative task relating to the Plan.

(b) The Company shall indemnify and hold harmless each Indemnified Person against any and all claims, losses, damages, and expenses, including reasonable attorney’s fees and court costs, incurred by that person on account of his good faith actions or failures to act with respect to his responsibilities relating to the Plan. The Company’s indemnification shall include payment of any amounts due under a settlement of any lawsuit or investigation, but only if the Company agrees to the settlement.

(1) An Indemnified Person shall be indemnified under this section only if he notifies an Appropriate Person at the Company of any claim asserted against or any investigation of the Indemnified Person that relates to the Indemnified Person’s responsibilities with respect to the Plan.

(A) A person is an “Appropriate Person” to receive notice of the claim or investigation if a reasonable person would believe that the person notified would initiate action to protect the interests of the Company in response to the Indemnified Person’s notice.

(B) The notice may be provided orally or in writing. The notice must be provided to the Appropriate Person promptly after the Indemnified Person becomes aware of the claim or investigation. No indemnification shall be provided under this section to the extent that the Plan or Company is materially prejudiced by the unreasonable delay of the Indemnified Person in notifying an Appropriate Person of the claim or investigation.

(2) An Indemnified Person shall be indemnified under this section with respect to attorneys’ fees, court costs or other litigation expenses or any settlement of such litigation only if the Indemnified Person agrees to permit the Company to select counsel and to conduct the defense of the lawsuit and agrees not to take any action in the lawsuit that the Company believes would be prejudicial to the interests of the Company.

(3) No Indemnified Person, including an Indemnified Person who had a Separation from Service, shall be indemnified under this section unless he makes himself reasonably available to assist the Company with respect to the matters in issue and agrees to provide whatever documents, testimony, information, materials, or other forms of assistance that the Company shall reasonably request.

(4) No Indemnified Person shall be indemnified under this section with respect to any action or failure to act that is judicially determined to constitute or be attributable to the gross negligence or willful misconduct of the Indemnified Person.

(5) Payments of any indemnity under this section shall be made only from the assets of the Company and shall not be made directly or indirectly from assets of the Plan. The provisions of this section shall not preclude such further indemnities as may be available under insurance purchased by the Company or as may be provided by the Company under any by‑law, agreement or otherwise, provided that no expense shall be indemnified under this section that is otherwise indemnified by an insurance contract purchased by the Company.

12.13 Fiduciaries

The fiduciaries named in this Article shall have only those specific powers, duties, responsibilities, and obligations as are specifically given them under this Plan or the Trust or otherwise delegated by the Board. The Employers shall have the sole responsibility for making the contributions required under Article 4 and Article 5, and the Company shall have the sole authority to appoint and remove the Trustee and to amend or terminate, in whole or in part, this Plan or the Trust. The Administrative Committee shall have the sole responsibility for the administration of this Plan, which responsibility is specifically described in this Plan and the Trust Agreement or otherwise delegated by the Board. The officers and Employees of the Company shall have the responsibility of implementing the Plan and carrying out its provisions as the Administrative Committee shall direct. The Investment Committee, the Trustee, and any investment manager shall have the sole responsibility for the administration of the Trust Fund and the management of the assets held under the Trust Fund, to the extent provided in the Trust Agreement. A fiduciary may rely upon any direction, information, or action of another fiduciary as being proper under this Plan or the Trust Agreement, and is not required under this Plan or the Trust Agreement to inquire into the propriety of any such direction, information, or action. It is intended under this Plan and the Trust Agreement that each fiduciary shall be responsible for the proper exercise of his or its own powers, duties, responsibilities, and obligations under this Plan and the Trust Agreement and shall not be responsible for any act or failure to act of another fiduciary. No fiduciary guarantees the Trust Fund in any manner against investment loss or depreciation in asset value. Any party may serve in more than one fiduciary capacity with respect to the Plan or Trust Agreement.

Whether or not a particular activity performed by the Administrative Committee, Investment Committee, a Committee member, or delegate is considered to rise to the level of a fiduciary duty shall depend on whether the person or entity is, when performing the activity, exercising the discretion with respect to the administration of the Plan, which under ERISA, if applicable, requires a fiduciary standard of conduct. In the absence of an activity involving such an exercise of discretion with respect to the Plan’s administration, the activity shall be considered ministerial, rather than fiduciary, in nature. If and when a Committee member or delegate is performing a “settlor” activity, under ERISA, including, by way of example, the adoption of an amendment to or decision to establish or terminate a plan, then such activity shall be deemed to be an exercise of “settlor” or sponsor responsibility and shall be subject to ordinary business judgment and not an exercise of fiduciary duty. The Administrative Committee and Investment Committee will not be subject to fiduciary liability or standards for any settlor or non-fiduciary responsibilities and/or duties delegated to it by the Board.

12.14 Notice of Address

Each person entitled to benefits from the Plan must file with the Administrative Committee or its agent, in writing, his post office address and each change of post office address. Any communication, statement, or notice addressed to such a person at his latest reported post office address will be binding upon him for all purposes of the Plan, and neither the Administrative Committee nor the Company or any Trustee shall be obliged to search for or ascertain his whereabouts.

12.15 Data

All persons entitled to benefits from the Plan must furnish to the Company such documents, evidence, or information, including information concerning marital status, as the Company considers necessary or desirable for the purpose of administering the Plan; and it shall be a condition of the Plan that each such person must furnish such information and sign such documents as the Company may require before any benefits become payable from the Plan. The Administrative Committee shall be entitled to distribute benefits to a non‑Spouse beneficiary in reliance upon the signed statement of the Participant that he is unmarried without any further liability to a Spouse if such statement is false.

12.16 Benefit Claims Procedures

The provisions of this section shall be subject to, and shall apply to, the extent required under Department of Labor Regulations section 2560.503‑1 (relating to the requirements of claims procedures). All decisions made under the procedures described in this section shall be final and there shall be no further right of appeal. No lawsuit may be initiated by any person before fully pursuing the procedures set out in this section, including the appeal permitted pursuant to subsection (d).

(a) The right of a Participant, Beneficiary, Alternate Payee, or any other person entitled to claim a benefit under the Plan shall be determined by the Administrative Committee, provided, however, that the Administrative Committee may delegate its responsibility to any person. All persons entitled to claim a benefit under the Plan shall be referred to as a “Claimant” for purpose of this section. The term “Claimant” shall also include, where appropriate to the context, any person authorized to represent the Claimant under procedures established by the Administrative Committee.

(1) The Claimant may file a claim for benefits by written notice to the Administrative Committee.

(2) Any claim for benefits under the Plan, pursuant to this section, shall be filed with the Administrative Committee no later than eighteen months after the date that a transaction occurred, or should have occurred, with respect to a Claimant’s Account (e.g., two years after benefits were credited, or should have been credited, to a Claimant’s Account, or eighteen months after any withdrawal or distribution occurred or should have occurred). The Administrative Committee in its sole discretion shall determine whether this limitation period has been exceeded.

(3) Notwithstanding anything to the contrary in this Plan, the following shall not be a claim for purposes of this section:

(A) A request for determination of eligibility, enrollment, or participation under the Plan without an accompanying claim for benefits under the Plan. The determination of eligibility, enrollment, or participation under the Plan may be necessary to resolve a claim, in which case such determination shall be made in accordance with the claims procedures set forth in this section.

(B) Any casual inquiry relating to the Plan, including an inquiry about benefits or the circumstances under which benefits might be paid under the Plan.

(C) A claim that is defective or otherwise fails to follow the procedures of the Plan (e.g., a claim that is addressed to a party, other than the Administrative Committee, or an oral claim).

(D) An application or request for benefits under the Plan.

(b) If a claim for benefits is wholly or partially denied, the Administrative Committee shall, within a reasonable period of time, but no later than 90 days after receipt of the claim (or 45 days after receipt of the claim in the case of a disability claim), notify the Claimant of the denial of benefits. In the case of a claim other than a disability claim, if special circumstances justify extending the period up to an additional 90 days, the Claimant shall be given written notice of this extension within the initial 90‑day period, and such notice shall set forth the special circumstances and the date on which a decision is expected. In the case of a disability claim, the Administrative Committee may give the Claimant written notice before the end of the initial 45‑period that it needs an additional 30 days to review the claim, provided that such notice shall set forth the circumstances beyond the control of the Administrative Committee justifying extending the period and the date on which a decision is expected. If special circumstances beyond the control of the Administrative Committee’s control justify extending the claim review period for an additional 30 days, the Claimant shall be provided written notice of this extension within the first 30-day period.

(c) A notice of denial:

(1) Shall be written in a manner calculated to be understood by the Claimant; and

(2) Shall contain:

(A) The specific reasons for denial of the claim;

(B) Specific reference to the Plan provisions on which the denial is based;

(C) A description of any additional material or information necessary for the Claimant to perfect the claim, along with an explanation as to why such material or information is necessary; and

(D) An explanation of the Plan’s claim review procedures and the time limits applicable to such procedures, including a statement of the Claimant’s right to bring a civil action under ERISA section 502(a) following an adverse determination on review.

(d) Within 60 days of the receipt by the Claimant of the written denial of his or her claim (or within 180 days of receipt in the case of a disability claim) or, if the claim has not been granted, within a reasonable period of time (which shall not be less than the applicable time period specified in subsection (b)), the Claimant may file a written request with the Administrative Committee that it conduct a full review of the denial of the claim. In connection with the Claimant’s appeal, upon request, the Claimant may review and obtain copies of all documents, records and other information relevant to the Claimant’s claim for benefits, but not including any document, record or information that is subject to any attorney‑client or work‑product privilege or whose disclosure would violate the privacy rights or expectations of any person other than the Claimant. The Claimant may submit issues and comments in writing and may submit written comments, documents, records, and other information relating to the claim for benefits. All comments, documents, records, and other information submitted by the Claimant shall be taken into account in the appeal without regard to whether such information was submitted or considered in the initial benefit determination.

(e) The Administrative Committee shall deliver to the Claimant a written decision on the claim promptly, but no later than 60 days (or 45 days in the case of a disability claim) after the receipt of the Claimant’s request for such review, unless special circumstances exist that justify extending this period up to an additional 60 days (or 45 days in the case of a disability claim). If the period is extended, the Claimant shall be given written notice of this extension during the initial 60‑day period (or 45-day period in the case of a disability claim) and such notice shall set forth the special circumstances and the date a decision is expected. The decision on review of the denial of the claim:

(1) Shall be written in a manner calculated to be understood by the Claimant;

(2) Shall include specific reasons for the decision;

(3) Shall contain specific references to the Plan provisions on which the decision is based;

(4) Shall contain a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and other information relevant to the Claimant’s claim for benefits; and

(5) Shall contain a statement of the Claimant’s right to bring a civil action under ERISA section 502(a) following an adverse determination on review.

(f) No legal action may be commenced after the later of:

(1) 180 days after receiving the written response of the Administrative Committee to an appeal, or

(2) 365 days after the Claimant’s original application for benefits.

(g) Any legal action in connection with the Plan must be filed in Harris County, Texas.

12.17 Member’s Own Participation

No member of the Administrative Committee or the Investment Committee may act, vote or otherwise influence a decision of the committee on which he or she serves specifically relating to his or her own participation under the Plan.

Article 13. Amendment and Termination

13.1 Amendment and Termination

The Company expects the Plan to be permanent and to continue indefinitely; however, this Plan is purely voluntary on the part of the Company and each Employer. The Company must necessarily and does hereby reserve the right to amend, modify, or terminate the Plan at any time by action of its Board. The Administrative Committee in its discretion may amend the Plan if it finds that such amendment does not significantly decrease benefits or significantly increase costs or it determines that the amendment is required to comply with applicable law.

No amendment of the Plan shall cause any part of the Trust Fund to be used for, or diverted to, purposes other than for the exclusive benefit of the Participants or their Beneficiaries covered by the Plan, or increase the duties and responsibilities of the Trustee without its consent, or decrease any Account balance.

13.2 Distribution on Termination

Upon termination of the Plan in whole or in part, or upon complete discontinuance of contributions to the Plan by the Company, the value of the proportionate interest in the Trust Fund of each Participant affected by such termination shall be determined by the Administrative Committee as of the date of such termination or discontinuance. The Accounts of such Participants shall be fully vested and nonforfeitable, and thereafter distribution shall be made to such Participants as directed by the Administrative Committee.

Upon the partial termination of the Plan, the Board may in its sole discretion determine the timing of a distribution of the balance of the affected Participants’ Accounts.

13.3 Successors

In case of the merger, consolidation, liquidation, dissolution or reorganization of an Employer, or the sale by an Employer of all or substantially all of its assets, provision may be made by written agreement between the Company and any successor corporation acquiring or receiving a substantial part of the Employer’s assets, whereby the Plan and the Trust Agreement will be continued by the successor. If the Plan is to be continued by the successor, then effective as of the date of the reorganization or transfer, the successor corporation shall be substituted for the Employer under the Plan and the Trust Agreement. The substitution of a successor corporation for an Employer will not in any way be considered a termination of the Plan.

13.4 Plan Merger or Transfer

This Plan shall not merge or consolidate with, or transfer assets and liabilities to, or accept a transfer from, any other employee benefit plan unless each Participant, Beneficiary, or Alternate Payee in this Plan will (if the Plan had then terminated) receive a benefit immediately after the merger, consolidation, or transfer which is not less than the benefit the Participant, Beneficiary, or Alternate Payee would have been entitled to receive immediately before the merger, consolidation, or transfer of assets (if this Plan had then terminated). Subject to these limitations, the Plan may transfer assets and liabilities to, or accept a transfer of assets and liabilities from, any other employee benefit plan which is qualified under Code section 401(a) where such a transfer has been authorized by agreement between the Company and the sponsor of the other employee benefit plan and is not prohibited by law.

Article 14. Participating Affiliates

14.1 Adoption of the Plan

The Board or, if authorized by the Board, the Administrative Committee may designate any Affiliate as an Employer under this Plan. The Affiliate shall become an Employer and a party to this Plan and the Trust Agreement upon acceptance of such designation effective as of the date specified by the Board or Administrative Committee.

14.2 Conditions of Participation

By accepting such designation or continuing as a party to the Plan and Trust, each Employer acknowledges that:

(a) It is bound by such terms and conditions relating to the Plan as the Company or the Administrative Committee may reasonably require;

(b) It must comply with all qualification requirements and employee benefit rules of the Code, ERISA and related regulations and hereby acknowledges the authority of the Company, the Administrative Committee, and the Investment Committee to review the Affiliate’s compliance procedures and to require changes in such procedures to protect the Plan’s qualification;

(c) It has authorized the Company, the Administrative Committee, and the Investment Committee to act on its behalf with respect to Employer matters pertaining to the Plan and the Trust Fund;

(d) It will cooperate fully with the Plan officials and their agents by providing such information and taking such other actions, as they deem appropriate for the efficient administration of the Plan and the Trust Fund; and

(e) Its status as an Employer under the Plan is expressly conditioned on its being and continuing to be an Affiliate of the Company.

14.3 Termination of Participation

(a) Withdrawal by Affiliate. Subject to the concurrence of the Board or Administrative Committee, any Affiliate may withdraw from the Plan and Trust, and end its status as an Employer hereunder, by communicating in writing to the Administrative Committee its desire to withdraw. The withdrawal shall be effective as of the date agreed to by the Board or Administrative Committee, as the case may be, and the Affiliate. Upon such withdrawal, the Plan shall not terminate.

(b) Termination by Company. The Company, acting through the Board or, if authorized by the Board, the Administrative Committee, reserves the right, in its sole discretion and at any time, to terminate the participation in this Plan of any Employer. Such termination shall be effective immediately, upon the notice of such termination from the Company to the Trustee and the Employer being terminated, whichever occurs first, or such later effective date agreed to by the Company. Upon such termination, this Plan shall not terminate.

14.4 Consequences of the Termination of an Employer

If an Employer ceases to participate in this Plan, for whatever reason, and the Plan is not terminated then, unless otherwise directed by the Board, the Administrative Committee shall elect, in its discretion, which of the following shall apply:

(a) The Administrative Committee may elect that the portion of the Plan attributable to the former Employer shall become a separate plan effective as of the date on which the Employer’s participation in this Plan terminates. The Administrative Committee shall inform the Trustee of the portion of the Trust Fund that is attributable to the participation of the terminated Employer. As soon thereafter as is administratively feasible, the Trustee shall set apart that portion of the Trust Fund as a separate trust fund that shall be part of the separate plan of the terminated Employer. Thereafter, the administration, control, and operation of the separate plan, with respect to the terminated Employer, shall be on a separate basis, in accordance with the terms of this Plan except that:

(1) The terminated Employer, not the Company or the Administrative Committee, shall be the sponsor and administrator of the separate plan and shall have all duties, responsibilities, and powers that the Company, Administrative Committee and Investment Committee have under this Plan; and

(2) The terminated Employer, not the Company, shall have the power to amend and terminate the separate plan, in accordance with the provisions of Plan section 13.1.

(b) Alternatively, the Administrative Committee may elect to maintain the Accounts of Participants employed by the terminated Employer as follows:

(1) Except as provided in paragraph (5), all Participants employed by the terminated Employer on the date on which the entity ceases participation in this Plan shall become Inactive Participants or Former Participants, as applicable.

(2) The Pre-Tax Deferral, Roth Contribution, Catch‑Up Contribution and After‑Tax Contribution elections of an Active Participant under Article 4 shall only apply to Earnings for the portion of the Plan Year ending on the Employer’s termination date.

(3) The terminated Employer shall transfer to the Trust Fund the Pre-Tax Deferrals, Roth Contributions, Catch‑Up Contributions, Matching Contributions and After‑Tax Contributions required under the Plan relating to Earnings through the effective date of the Employer’s termination of participation in this Plan.

(4) For purposes of being eligible to receive a distribution of his or her Account, an Inactive Participant described in paragraph (1) shall not be treated as having a Separation from Service unless and until the Administrative Committee determines that the Participant is eligible to receive a distribution under the provisions of Code section 401(k)(2)(B)(i).

(5) If a Participant described in paragraph (1) becomes an Employee of another Employer immediately after the effective date of the prior Employer’s termination of participation in this Plan, then the Participant shall be treated under the Plan as having transferred employment from one Employer to another.

(6) Should the Administrative Committee elect to take alternative action under this Section 14.4(b), the name of the terminated Employer and the effective date of such action will be set forth on Appendix I.

(c) With the consent of the Employer that is no longer participating in the Plan, the Company or Administrative Committee may take such other actions with respect to the Accounts of Participants employed by that Employer as are permitted under the Code and ERISA.

Article 15. Top‑Heavy Provisions

15.1 Application of Top‑Heavy Provisions

The provisions of this Article shall be interpreted and administered in accordance with the requirements of Code section 416 and related Treasury Regulations. The provisions of this Article shall apply for the Plan Year if, as of the Determination Date for that Plan Year, the Top‑Heavy Ratio exceeds 60 percent.

15.2 Definitions Applicable to this Article

In addition to the terms defined in Plan section 2.1 or elsewhere in this Plan, whenever used in this Article, the following terms shall have the respective meanings set forth below, unless expressly provided otherwise. When the defined meaning is intended, the term is capitalized.

(a) “Aggregation Group” means each Qualified Plan of the Company or any Affiliate in which a Key Employee is a participant and any other Qualified Plan which enables a Qualified Plan of the Company or any Affiliate covering a Key Employee to meet the requirements of Code sections 401(a)(4) or 410. On behalf of the Company, the Administrative Committee may elect to include within the Aggregation Group any other Qualified Plan, together with the Qualified Plans referenced in the preceding sentence, provided that such expanded Aggregation Group continues to satisfy the requirements of Code sections 401(a)(4) and 410(b) for the Plan Year.

(b) “Determination Date” means the last day of the preceding Plan Year.

(c) “Key Employee” means, effective for Plan Years beginning after 2001, any Employee or a former Employee (including any deceased Employee) who, at any time during the Plan Year, is one of the following:

(1) An officer of the Company or any Affiliate whose Section 415 Compensation exceeds $130,000, as adjusted under Code section 416(i)(1) for Plan Years commencing after 2002, provided however, that the number of Employees included as Key Employees under this paragraph shall not exceed the lesser of:

(A) 50 Employees; or

(B) The greater of three Employees or 10 percent of all Employees of the Company and all Affiliates.

(2) A five‑percent owner of the Company or any Affiliate.

(3) A one‑percent owner of the Company or any Affiliate whose Section 415 Compensation exceeds $150,000.

Only Section 415 Compensation attributable to services performed during the Plan Year for the Company or an Affiliate shall be included. Ownership shall be determined in accordance with Code section 318 (as modified by Code section 416(i)(1)(B)(iii)). A Beneficiary or Alternate Payee whose rights under the Plan derive from a Key Employee shall also be treated as a Key Employee.

(d) “Non‑Key Employee” means any Employee who is not a Key Employee.

(e) “Top‑Heavy Ratio” means the ratio determined under Plan section 15.3.

15.3 Determination of Top‑Heavy Ratio

The Top‑Heavy Ratio for a Plan Year shall be determined as follows:

(a) General Rule. The numerator of the Top‑Heavy Ratio is the sum of the amounts described in subsection (b) under all Qualified Plans in the Aggregation Group for each Key Employee. The denominator of the Top‑Heavy Ratio is the sum of the amounts described in subsection (b) under all Qualified Plans in the Aggregation Group for all Employees.

(b) Included Amounts. When determining the Top‑Heavy Ratio, the following amounts shall be included:

(1) The Employee’s total Account balance as of the Determination Date under this Plan;

(2) The Employee’s total account balance as of the Determination Date under all other Qualified Plans that are defined contribution plans included in the Aggregation Group;

(3) The present value as of the Determination Date of the Employee’s accrued benefit under all Qualified Plans that are defined benefit plans included in the Aggregation Group.

(c) Special Rules. For purposes of computing the Top‑Heavy Ratio and included amounts, the following rules shall apply:

(1) The present value of accrued benefits shall be determined using reasonable actuarial assumptions.

(2) In the case of a distribution made for a reason other than severance from employment, death, or Disability (e.g., in‑service withdrawals), this provision shall be applied by substituting “five‑year period” for “one‑year period.”

(3) Any Rollover, Roth Rollover or After-Tax Rollover Contribution (or similar transfer) initiated by the Employee and made after December 31, 1983, to a Qualified Plan in the Aggregation Group shall be excluded when determining account balances with respect to the transferee plan.

(4) Account balances and accrued benefits shall be taken into account only to the extent attributable to contributions by the Company or Affiliate and contributions by the Employee while employed by the Company or an Affiliate.

(5) The present values of accrued benefits and account balances of any individual who has not performed services for the Company or any Affiliate during the one‑year period ending on the Determination Date shall not be taken into account when determining the Top‑Heavy Ratio.

(6) Account balances or accrued benefits of an Employee shall not be taken into account if the Employee is not a Key Employee for the Plan Year being tested but was a Key Employee in a prior Plan Year.

(7) To the extent required by Code section 416(e), contributions and benefits relating to Social Security or similar programs under federal or state law shall not be taken into account in determining the Top‑Heavy Ratio.

15.4 Required Minimum Allocations

If the provisions of this Article apply for the Plan Year because the Top‑Heavy Ratio exceeds 60 percent, then with respect to the defined contribution minimum allocation required by Code section 416(c)(2) and related Treasury Regulations, the contributions shall be made under the Retirement Plan on behalf of each Non‑Key Employee who is a Participant who has not incurred a Separation from Service as of the last day of the Plan Year (regardless of whether the Non‑Key Employee has less than 1,000 hours of service (or the equivalent) and regardless of the Non‑Key Employee’s level of Section 415 Compensation), in an allocation for that Plan Year of not less than the lesser of:

(a) Three percent of the Participant’s Section 415 Compensation, or

(b) The percentage equal to the largest contribution, expressed as a percentage of Section 415 Compensation, received by any Key Employee under all defined contribution plans in the Aggregation Group.

For purposes of satisfying the requirements of this section, Pre-Tax Deferrals and Roth Contributions shall not be included, for any Employee who is a Non‑Key Employee, but shall be included for any Participant who is a Key Employee. Effective for Plan Years beginning after 2001, the allocation of Matching Contributions shall be included for all Employees. If any Qualified Plan in the Aggregation Group is a defined benefit plan, then any Participant who participates both in a defined benefit plan and would otherwise be entitled to a minimum contribution under this section shall receive the defined benefit minimum prescribed under Code section 416(c)(1) and related Treasury Regulations under the defined benefit plan and shall not receive the minimum allocation under this section.

15.5 Required Minimum Vesting

If the provisions of this Article apply for the Plan Year because the Top‑Heavy Ratio exceeds 60 percent, then each Participant who has not incurred a Separation from Service as of the last day of the Plan Year shall continue to vest in his or her Matching Account and any defined contribution minimum allocation, as described in Plan section 15.4, for the Plan Year in accordance with the provisions of Plan section 3.5, which provides for vesting that is in all cases equal to or more rapid than required by Code section 416(b).

15.6 Employees Covered by Collective Bargaining Agreement

Notwithstanding any provision of this Article to the contrary, the provisions of Plan sections 15.4 and 15.5 shall not apply with respect to any Represented Employee covered by a collective bargaining agreement where retirement benefits were the subject of good faith bargaining between the Employer and the union.

Article 16. Miscellaneous Provisions

16.1 No Enlargement of Employment Rights

This Plan is strictly a voluntary undertaking on the part of the Company and the Employers and shall not be deemed to constitute a contract between the Employers and any Employee or Participant, Beneficiary, or Alternate Payee, or to be consideration for, or an inducement to, or a condition of, the employment of any Employee. Nothing contained in this Plan or any modification of the same or act done in pursuance hereof shall be construed as giving any person any legal or equitable right against the Employer, the Trustee, or the Trust Fund, unless specifically provided herein, or as giving any person a right to be retained in the employ of the Employer. All Participants shall remain subject to assignment, reassignment, promotion, transfer, layoff, reduction, suspension, and discharge to the same extent as if this Plan had never been established. No Participant, Beneficiary, or Alternate Payee, before satisfying all conditions for receiving benefits, shall have any right or interest in or to any portion of the Trust Fund. No one shall have any right to benefits, except to the extent provided in this Plan.

16.2 No Examination or Accounting

Neither this Plan nor any action taken thereunder shall be construed as giving any person the right to an accounting or to examine the books or affairs of the Company or any Affiliate.

16.3 Investment Risk

The Participants and their Beneficiaries shall assume all risks in connection with any decrease in the value of any assets or funds which may be invested or reinvested in the Trust Fund which supports this Plan.

16.4 Non‑Alienation

(a) Except as otherwise permitted by the Plan, no benefit payable at any time under the Plan shall be subject to the debts or liabilities of a Participant or his or her Beneficiary. Any attempt to alienate, sell, transfer, assign, pledge, or otherwise encumber any such benefit, whether presently or thereafter payable, shall be void. Except as provided in this section, no benefit under the Plan shall be subject in any manner to attachment, garnishment, or encumbrance of any kind.

(b) Payment may be made from a Participant’s Account to an Alternate Payee, pursuant to a Qualified Domestic Relations Order.

(1) The Administrative Committee shall establish reasonable written procedures for reviewing court orders made, pursuant to state domestic relations law (including a community property law), relating to child support, alimony payments, or marital property rights of a Spouse, former Spouse, child, or other dependent of a Participant and for notifying Participants and Alternate Payees of the receipt of such orders and of the Plan’s procedures for determining if the orders are Qualified Domestic Relations Orders and for administering distributions under Qualified Domestic Relations Orders.

(2) Except as may otherwise be required by applicable law, such Qualified Domestic Relations Orders may not require a retroactive transfer of all or part of a Participant’s Account to or for the benefit of an Alternate Payee without permitting an appropriate adjustment for earnings and investment gains or losses that have occurred in the interim, nor shall such orders require the Plan to provide rights to Alternate Payees that are not available to Beneficiaries generally.

(3) In cases in which a full and prompt payment of amounts assigned to an Alternate Payee will not be made, pursuant to this subsection, the assigned amounts will be transferred, within a reasonable time after determination that the order is a Qualified Domestic Relations Order, to a separate Account for the benefit of the Alternate Payee and invested in accordance with the Alternate Payee’s investment elections pursuant to Article 9.

(4) No amount that is segregated pending a determination of whether a domestic relations order is a Qualified Domestic Relations Order or transferred to a separate Account for the benefit of the Alternative Payee shall be taken into account when determining the amount that:

(A) A Participant may withdraw from his or her Account, pursuant to Plan section 7.2;

(B) A Participant may receive in a Plan loan, pursuant to Plan section 8.2; or

4Section 

(C) A Participant (or his or her Beneficiary) may receive in a distribution, pursuant to Plan section 7.3 or 7.5.

(c) Payment may be made from an Account, to the extent required by a federal tax levy made pursuant to Code section 6331 or by the United States’ collection of a judgment resulting from an unpaid federal tax assessment. Payment may be made at the time required by the tax levy or judgment collection order, even if payment would not otherwise be made at that time under the terms of the Plan and payment from the Plan would not otherwise be permitted at that time under Code section 401(a), 401(k), or 411(a)(11).

(d) Payments from an Account may be offset to the extent permitted under Code section 401(a)(13)(C) (relating to offsets regarding breaches of duty with respect to the Plan).

(e) A Participant or Beneficiary may disclaim his or her Account, or a portion thereof, subject to the rules which may be modified from time to time by the Administrative Committee.

16.5 Incompetency

Every person receiving or claiming benefits under the Plan shall be conclusively presumed to be mentally competent and of age until the date on which the Administrative Committee (or its delegee) receives a written notice, in a form and manner acceptable to the Administrative Committee (or its delegee), that such person is incompetent or a minor, for whom a guardian or other person legally vested with the care of his or her person or estate has been appointed; provided, however, that if the Administrative Committee (or its delegee) shall find that any person to whom a benefit is payable under the Plan is unable to care for his or her affairs because of incompetency, or is a minor, any payment due (unless a prior claim therefore shall have been made by a duly appointed legal representative) may be paid to the Spouse, a child, a parent, a brother or sister, or to any person or institution deemed by the Administrative Committee (or its delegee) to have incurred expenses for such person otherwise entitled to payment. To the extent permitted by law, any such payment so made shall be a complete

discharge of liability therefore under the Plan. In the event that a guardian of the estate of any person receiving or claiming benefits under the Plan shall be appointed by a court of competent jurisdiction or a person shall otherwise qualify as a guardian within the sole discretion of the Administrative Committee (or its delegee) and such guardian provides proper proof of appointment, qualification, or continuing qualification, as applicable, in a form and manner acceptable to the Administrative Committee (or its delegee), then, to the extent permitted by law:

(a) Such guardian may act for the Participant, Beneficiary, or Alternate Payee and make any election required of or permitted by the Participant, Beneficiary, or Alternate Payee under this Plan, and such action or election shall be deemed to have been taken by the Participant, Beneficiary, or Alternate Payee; and

5Section 

(b) Benefit payments may be made to such guardian, and any such payment so made shall be a complete discharge of any liability therefore under the Plan.

16.6 Records Conclusive

The records of the Company, Employers, the Administrative Committee, the Investment Committee and the Trustee shall be conclusive in respect to all matters involved in the administration of the Plan.

16.7 Counterparts

This Plan may be executed in any number of counterparts, each of which shall be deemed to be an original. All the counterparts shall constitute but one and the same instrument and may be sufficiently evidenced by any one counterpart.

16.8 Service of Legal Process

The Trustee, the members of the Administrative Committee, and the Secretary of the Company are hereby designated agents of the Plan for the purpose of receiving service of summons, subpoena, or other legal process.

16.9 Uncashed or Unclaimed Benefits

(a) Stale Checks. Effective on or after August 8, 2016, if a distribution check is issued under the Plan and such distribution check is not cashed within 6 months after issuance, the check will be characterized as stale, and the funds re-deposited into a special account under the Plan. Such funds shall be characterized on an after-tax basis and effective December 1, 2016, or as soon as practicable thereafter but in no event later than December 31, 2016, such amounts will be invested in the Plan’s Stable Value Fund, defined in Appendix B(a) of the Plan, or such other fund as determined within the discretion of the Administrative Committee. The check will be reissued upon request by the Participant pursuant to procedures established by the Administrative Committee.

(b) Lost Participants. In the event that the Administrative Committee or its delegee, after having made a diligent search, is unable to locate a Participant, Beneficiary, or Alternate Payee who is entitled to benefits under this Plan, such benefits shall be treated as a forfeiture under Plan section 3.6. In the event that the Participant, Beneficiary, or Alternate Payee whose Account is subject to such forfeiture subsequently asserts a valid claim for benefits, the Account will be restored in the manner described in Plan section 3.6.

16.10 Qualified Military Service

Notwithstanding any provision of this Plan to the contrary, contributions, benefits and Service credit required with respect to qualified military service, within the meaning of Code section 414(u), will be provided in accordance with the mandatory provisions of Code section 414(u). In addition, in compliance with the Heroes Earnings Assistance and Relief Tax Act (“HEART), the following provisions shall apply notwithstanding any Plan provision to the contrary:

(a) Effective January 1, 2007, if the Participant dies while on qualified military service, the Participant’s Beneficiary shall be entitled to any benefit under the Plan (other than additional allocations related to the period of qualified military service) to the same extent that the Participant would have been entitled to such benefit had the Participant resumed employment and then incurred a Separation from Service on account of death.

(b) Effective January 1, 2009, Differential Wages shall be treated as Base Pay, as provided in Plan section 2.1(p)(2)(H), and Section 415 Compensation, as provided in Plan section 2.1(nnn)(2)(D), paid to an Active Participant by the Employer making the payment. For this purpose, Differential Wages means any payment made by an Employer with respect to any period during which the Employee is performing qualified military service and represents all or a portion of the wages the Employee would have received from the Employer if the Employee were performing service for the Employer.

(c) Effective January 1, 2009 and even if the Employee is receiving Differential Wages, a Participant performing qualified military service will be treated as having incurred a Separation from Service during the period of such qualified military service for purposes of Plan section 7.3, but only with respect to the Participant’s Pre-Tax Account and Roth Account. If the Participant elects to receive a distribution under this deemed Separation from Service, then such Participant shall not be permitted to make Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions or After‑Tax Contributions during the six‑month period beginning on the date of the distribution. Effective for withdrawals requested after August 8, 2016, if a Participant is suspended from making any Pre-Tax Deferrals, Roth Contributions, Catch-Up Contributions and/or After Tax Contributions in accordance with the sentence above, such contributions will be automatically reinstated upon expiration of the six-month suspension period at the Default Percentage, as applicable, or if the Participant was not subject to automatic enrollment or had opted out of automatic enrollment at the percentage in place prior to the suspension.

*    *    *

6Section 

In Witness Whereof, Occidental Petroleum Corporation has caused this amended and restated Plan to be executed this 27th day of December, 2019.

Occidental Petroleum Corporation

/s/ Darin S. Moss    

By: Darin S. Moss

Its: Vice President, Human Resources

7

EX-10.32

Exhibit 10.32

ANADARKO RETIREMENT RESTORATION PLAN(As Amended and Restated Effective as of December 31, 2019)

TABLE OF CONTENTS

Page

ARTICLE I PURPOSES OF THE PLAN    1

ARTICLE II DEFINITIONS    1

2.01Definitions    1

ARTICLE III ADMINISTRATION    4

3.01Administration by Committee    4

3.02Administration of Plan    4

3.03Action by Committee    4

3.04Delegation    4

3.05Reliance Upon Information    4

3.06Indemnity of Plan Administration Employee    5

ARTICLE IV ELIGIBILITY    5

ARTICLE V AMOUNT OF BENEFIT    6

5.01General Benefits    6

5.02Supplemental Benefits    6

5.03Other Supplemental Benefits    7

ARTICLE VI PAYMENT OF BENEFIT    7

6.01Lump Sum Benefit    7

6.02Payment Under Retirement Plan Before 2009    7

6.03Specified Employees    8

ARTICLE VII PARTICIPANT’S RIGHTS AND NATURE OF PLAN    8

ARTICLE VIII AMENDMENT AND DISCONTINUANCE    8

ARTICLE IX CLAIMS PROCEDURE    9

9.01Filing a Claim    9

9.02Denial of Claim    10

9.03Reasons for Denial    10

9.04Review of Denial    10

9.05Decision Upon Review    10

9.06Other Procedures    11

9.07Finality of Determinations; Exhaustion of Remedies    11

9.08Effect of Committee Action    11

ARTICLE X MISCELLANEOUS    12

10.01Construction    12

10.02Powers of the Company    12

10.03Beneficiary Designations    12

10.04Limitation of Rights    13

10.05Distribution due to Qualified Domestic Relations Order    13

10.06Nonalienation of Benefits    14

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10.07Facility of Payments    14

10.08Withholding of Taxes    14

10.09Adoption of Plan by Affiliated Entity    14

10.10Waiver    14

10.11Notice    14

10.12Severability    15

10.13Gender, Tense and Headings    15

10.14Governing Law    15

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ANADARKO RETIREMENT RESTORATION PLAN
(As Amended and Restated Effective as of December 31, 2019)

ARTICLE I

PURPOSES OF THE PLAN

The purposes of the Plan are (i) to recognize the value to the Company of the past and present services of the Eligible Employees and (ii) to encourage their continued employment service by providing benefits for their future retirement security. The Plan was created because of certain Limitations which are imposed on the Retirement Plan by the Code.

The Plan was originally effective as of January 1, 1995, amended effective as of July 31, 2003, and amended and restated generally effective as of November 7, 2007, and again effective as of January 1, 2017 and as of August 8, 2019. The Plan as set forth herein constitutes an amendment and restatement of the Plan as in effect immediately prior to the Effective Date in order to modify certain provisions of the Plan related to Plan administration. This amendment and restatement of the Plan shall be effective as of the Effective Date.

With respect to Participants other than Limited 415 Participants, the Plan is intended as an unfunded plan to be maintained primarily for the purpose of providing deferred compensation for a “select group of management or highly compensated employees” within the meaning of such phrase for purposes of Sections 201(2), 301(a)(3) and 401(a)(1) of the Act, and as such it is intended that the Plan be exempt from the participation and vesting, funding, and fiduciary responsibility requirements of Title I of the Act. The Plan is also intended to qualify for simplified reporting under U.S. Department of Labor Regulation Section 2530.104-23, which provides for an alternative method of compliance for plans described in such regulation. With respect to Limited 415 Participants, the portion of the Plan that provides benefits to such Limited 415 Participants solely due to limitations applicable to the Retirement Plan by reason of Code Section 415 is intended to be treated as a separate plan that is an “excess benefit plan” within the meaning of such phrase for purposes of Sections 3(36) and 4(b)(5) of the Act. Moreover, the Plan is intended to comply with the requirements of Code Section 409A for nonqualified deferred compensation plans to the extent applicable. The Plan is not intended to satisfy the tax qualification requirements of Code Section 401(a).

ARTICLE IIDEFINITIONS

2.01Definitions. Where the following words and phrases appear in this Plan they shall have the respective meanings set forth below, unless their context clearly indicates to the contrary.

(a)Act. The Employee Retirement Income Security Act of 1974, as amended and the regulations and other authority issued thereunder by the appropriate governmental authority.

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(b)Actuarial Equivalent. The equivalence of a benefit, as determined by an actuary appointed by the Committee (“Actuary”), in terms of another benefit utilizing such assumptions as in the aggregate represent the Actuary’s best estimate of equivalent value for the purpose for which the determination is being made.

(c)Affiliated Entity. An entity which is affiliated by common ownership or control with the Company.

(d)Beneficiary. Means the beneficiary or beneficiaries designated by the Participant, in accordance with Section 10.03, to receive any amounts distributable under the Plan upon his death.

(e)Code. The Internal Revenue Code of 1986, as amended and the regulations and other authority related thereto.

(f)Committee. “Committee” means the committee appointed by the Board to administer the Plan; provided, however, that if the Board has not appointed a committee, then each reference herein to the “Committee” shall instead refer to the Board.

(g)Company. Anadarko Petroleum Corporation or its successor in interest.

(h)Directors. The Board of Directors of the Company.

(i)Effective Date. December 31, 2019, as to this amendment and restatement of the Plan.

(j)Eligible Employee. An Employee who participates in the Retirement Plan and whose benefits are reduced by Limitations or whose taxable compensation has been reduced as a result of an election by the Employee to defer compensation pursuant to a deferred compensation plan maintained by an Employer.

(k)Employee. An Employee as defined in the Retirement Plan.

(l)Employer. The Company or an Affiliated Entity which has been designated by the Company as a participating employer in the Plan and has adopted the Plan.

(m)Employment. Means that the individual is in employment as an Employee. In this regard, neither the transfer of a Participant from employment by an Employer to employment by an Affiliated Entity nor the transfer of a Participant from employment by an Affiliated Entity to employment by an Employer shall be deemed to be a Separation from Service by the Participant.

(n)Limitations. The aggregate of the limitations imposed under Code Sections 401(a)(17) and 415 plus any amounts deferred as the result of an election by an Employee to defer compensation pursuant to a deferred compensation plan

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maintained by an Employer. From and after the Effective Date, the term “Limitations” shall also include any amendment to the Retirement Plan that is adopted on or after the Effective Date and that is expressly identified in connection with its adoption as an amendment that is intended to reduce or limit accruals under the Retirement Plan with respect to an Employee who is a “highly compensated employee” (as defined in Code Section 414(q)) due to the application of the Nondiscrimination Rules. Notwithstanding the preceding provisions of this Section 2.01(n), with respect to a Limited 415 Participant, for all purposes of the Plan the term “Limitations” shall mean solely the limitation imposed by Code Section 415 on the amount of benefits which may be earned or paid under the Retirement Plan.

(o)Limited 415 Participant. Any Employee whose benefit under the Retirement Plan is limited by the limitation imposed by Code Section 415 and who has not otherwise been designated as a Participant in the Plan by the Committee pursuant to the provisions of Article IV hereof.

(p)Nondiscrimination Rules. The nondiscrimination rules set forth in Code Section 401(a)(4), Code Section 410(b) or other provisions of the Code that are applicable to the Retirement Plan and that are intended to prevent discrimination in favor of “highly compensated employees” (as defined in Code Section 414(q)).

(q)Participant. Any Eligible Employee who has been designated by the Committee to participate in the Plan or any other individual who has an accrued benefit under the Plan which has not been fully distributed. The term “Participant” shall include a Limited 415 Participant except where expressly provided otherwise in the Plan.

(r)Plan. The Anadarko Retirement Restoration Plan, as it may be amended from time to time.

(s)Plan Year. The twelve consecutive month period commencing on January 1 of each year.

(t)Retirement Plan. The Anadarko Retirement Plan, as amended from time to time; provided, however, that for plan years beginning after December 31, 2019, the “Retirement Plan” means the Anadarko Retirement Plan and the Occidental Oil and Gas Consolidated Retirement Plan (Part E only).

(u)Section 16 Officer. An Eligible Employee who is subject to Section 16 of the Securities and Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

(v)Separation from Service. The Participant’s separation from service with the Employer and all Affiliated Entities, within the meaning of Code Section 409A.

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(w)Specified Employee. Any Participant who is a “Specified Employee” (as defined in Code Section 409A) upon his Separation from Service, as determined by the Company or the Committee.

ARTICLE IIIADMINISTRATION

3.01Administration by Committee. The Committee shall be the plan administrator with respect to the Plan, except that for all matters (including, without limitation, interpretation of the Plan) directly relating to participation, claims or benefits associated with individuals who are then Section 16 Officers, the Committee shall be the Executive Compensation Committee of the Board of Directors of Occidental Petroleum Corporation.

The members of the Committee shall not receive any special compensation for serving in their capacities as members, but shall be reimbursed by the Company for any reasonable expenses incurred in connection therewith. No bond or other security need be required of the Committee or any member thereof.

3.02Administration of Plan. The Committee shall operate, administer, interpret, construe and construct the Plan, including correcting any defect, supplying any omission or reconciling any inconsistency. The Committee shall have all powers necessary or appropriate to implement and administer the terms and provisions of the Plan, including the power to make findings of fact. The determination of the Committee as to the proper interpretation, construction, or application of any term or provision of the Plan shall be final, binding, and conclusive with respect to all Participants and other interested persons.

3.03Action by Committee. A majority of the members of the Committee shall constitute a quorum for the transaction of business, and the vote of a majority of those members present at any meeting at which a quorum is present shall decide any question brought before the meeting and shall be the act of the Committee. In addition, the Committee may take any other action otherwise proper under the Plan by an affirmative vote, taken without a meeting, of a majority of its members.

3.04Delegation. The Committee may, in its discretion, delegate one or more of its duties to its designated agents or to an Employee, but it may not delegate its authority to make the determinations specified in Section 3.02.

3.05Reliance Upon Information. No member of the Committee shall be liable for any decision, action, omission, or mistake in judgment, provided that he acted in good faith in connection with the administration of the Plan. Without limiting the generality of the foregoing, any decision or action taken by the Committee (or member thereof) in reasonable reliance upon any information supplied to it by the Directors, any Employee, the Employer’s legal counsel, the Employer’s independent accountants or the Actuary, shall be deemed to have been taken in good faith.

The Committee (or an individual member thereof) may consult with legal counsel, who may be counsel for the Employer or other counsel, with respect to its obligations or duties hereunder,

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or with respect to any action, proceeding or question at law, and shall not be liable with respect to any action taken or omitted, in good faith, pursuant to the advice of such counsel.

3.06Indemnity of Plan Administration Employee. To the full extent permitted by law, the Company shall defend, indemnify and hold harmless each past, present and future member of the Committee and each other Employee who acts in the capacity of an agent, delegate or representative of the Committee under the Plan (hereafter, all such indemnified persons shall be jointly and severally referred to as “Plan Administration Employee”) against, and each Plan Administration Employee shall be entitled without further act on his part to indemnity from the Company for, any and all losses, claims, damages, judgments, settlements, liabilities, expenses and costs (and all actions in respect thereof and any legal or other costs and expenses in giving testimony or furnishing documents in response to a subpoena or otherwise), including the cost of investigating, preparing or defending any pending, threatened or anticipated action, claim, suit or other proceeding, whether or not in connection with litigation in which the Plan Administration Employee is a party (collectively, the “Losses”), as and when incurred, directly or indirectly, relating to, based upon, arising out of, or resulting from his being or having been a Plan Administration Employee; provided, however, that such indemnity shall not include any Losses incurred by such Plan Administration Employee with respect to any matters as to which he is finally adjudged in any such action, suit or proceeding to have been guilty of gross negligence or intentional misconduct in the performance of his duties as a Plan Administration Employee. The foregoing right of indemnification shall be in addition to any liability or obligation that any Employer may otherwise have to the Plan Administration Employee, and shall be in addition to all other rights to which the Plan Administration Employee may be entitled as a matter of law, contract, or otherwise.

The Plan Administration Employee shall have the right to retain counsel of its own choice to represent him, provided that such counsel is acceptable to the Employer (which acceptance shall not be unreasonably withheld). The Company shall pay the fees and expenses of such counsel, and such counsel shall to the full extent consistent with its professional responsibilities cooperate with the Employer and its counsel. The rights of indemnification under this Section 3.06 shall inure to the benefit of the successors and assigns, and the heirs, executors, administrators and personal representatives of each Plan Administration Employee, shall be in addition to any liability or obligation that any Employer may otherwise have to the Plan Administration Employee and shall be in addition to all other rights to which the Plan Administration Employee may be entitled as a matter of law, contract, or otherwise.

ARTICLE IV

ELIGIBILITY

Each Employee who was a Participant in the Plan immediately prior to the Effective Date shall continue as a Participant in the Plan as of the Effective Date.

From and after the Effective Date, before the start of a Plan Year, or at any other time and from time to time, the Committee, in its sole discretion, shall designate the Participants and the effective date and other terms and conditions of participation; provided, however, an Employee may be a Participant only if the Committee determines that such individual is “a member of a select

5

group of management or highly compensated employees” of the Employer within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of the Act. Notwithstanding the foregoing, any Employee whose benefit under the Retirement Plan is limited by the limitation imposed by Code Section 415 and who is not otherwise designated by the Committee as a Participant pursuant to the preceding sentence shall automatically participate in the Plan as a Limited 415 Participant.

ARTICLE VAMOUNT OF BENEFIT

5.01General Benefits. The benefits payable under this Plan to a Participant (or Beneficiary thereof) shall be paid at the time and in the manner described in Article VI based upon an amount equal to the Actuarial Equivalent of the excess, if any of (a) over (b), where:

(a) is the benefit that would have been payable to such Participant or Beneficiary under the Retirement Plan if the provisions of the Retirement Plan were administered without regard to the Limitations; and

(b)is the benefit, if any, that is in fact payable to such Participant or Beneficiary under the Retirement Plan.

Benefits determined under this Section 5.01 shall be computed by the Actuary in accordance with the foregoing and with the objective that such recipient should receive under the Plan and the Retirement Plan that total aggregate amount which would have been payable to that recipient solely under the Retirement Plan but without regard to imposition of the Limitations. The benefits provided under this Plan shall be subject to the same vesting schedule that applies to the Participant under the Retirement Plan, and he shall thus vest hereunder on the same terms as provided in the Retirement Plan but subject to Schedule A.

5.02Supplemental Benefits. In the case of a Participant (other than a Limited 415 Participant) who would have been entitled to supplemental benefits under the Retirement Plan but for the fact that his compensation for the calendar year ending December 31, 2002 exceeded the $200,000 limit under the terms of the Retirement Plan, such Participant shall be entitled to a supplemental benefit under this Plan as determined in accordance with the formula described in this Section 5.02.

If the Employment of a Participant is terminated and (1) such termination is designated by the Employer, in its sole discretion, as being part of a “reduction in force program,” (2) the Participant’s designated termination date occurs on or after July 31, 2003 and on or before December 31, 2003, and (3) as of the designated termination date, the Participant had attained the age of 45, completed 5 or more years of Vesting Service (as defined in the Retirement Plan) and the sum of the Participant’s age and Vesting Service equals or exceeds 60, such Participant will qualify for an early retirement benefit under the Retirement Plan commencing as of his Normal Retirement Date (as defined in the Retirement Plan) or as of the first day of the first month coinciding with or next following the date he attains the age of 55 or the first date of any subsequent month pursuant to the terms of the Retirement Plan, reduced as described under the Retirement Plan. Such Participant’s

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Annuity Starting Date (as defined in the Retirement Plan) shall be as described under the Retirement Plan. A Participant who satisfied the conditions in clauses (1), (2), and (3) of the first sentence of this paragraph shall not be eligible for the supplemental benefit under the Retirement Plan if his compensation for the calendar year ending December 31, 2002 exceeded the $200,000 limit under the terms of the Retirement Plan, and thus such Participant shall receive the Actuarial Equivalent of such supplemental benefits under this Plan in the manner, and at the time, as prescribed in Article VI.

5.03Other Supplemental Benefits. Upon Separation from Service, the Company shall pay or cause to be paid to such Participant (or his Beneficiary) other supplemental benefits as determined by the Directors and contained in any other Employer-provided plan or program or in the Participant’s employment contract or other agreement with the Employer; provided that such supplemental benefits for each Participant entitled to such other supplemental benefits are set forth on Schedule A attached and incorporated into this Plan for all purposes (which may be amended or supplemented from time to time), including the amount, type, and terms and conditions of such other supplemental benefits. Other supplemental benefits under this Section 5.03 shall be vested and nonforfeitable to the extent provided in the applicable Employer-paid plan or program, the Participant’s employment contract or other agreement with the Employer, or as set forth on Schedule A to the Plan. Notwithstanding the foregoing, this Section 5.03 shall not be construed to provide duplicate other supplemental benefits under the Plan, or under any such applicable Employer-provided plan or program, or the Participant’s employment contract or other agreement with the Employer, or as set forth on Schedule A to the Plan, to or on behalf of any Participant or Beneficiary.

ARTICLE VIPAYMENT OF BENEFIT

6.01Lump Sum Benefit. Subject to Sections 6.02 and 6.03, the form of the benefits payable under Article V shall be a cash lump sum payment that is made within ninety (90) days after the date of the Participant’s Separation from Service.

6.02Payment Under Retirement Plan Before 2009. If a Participant (a) incurs a Separation from Service after December 31, 2004 and (b) receives or commences receipt of any pension benefits payment under the Retirement Plan at any time before January 1, 2009, such Participant (or his Beneficiary) shall receive his benefits under this Plan in a cash lump sum payment that is made within ninety (90) days from the date that benefits are paid, or commence to be paid, under the terms of the Retirement Plan. If a Participant (a) incurs a Separation from Service after December 31, 2004 and (b) does not receive or commence receipt of any pension benefits payment under the Retirement Plan at any time before January 1, 2009, such Participant (or his Beneficiary) shall receive his benefits under this Plan in a cash lump sum payment that is made within ninety (90) days after December 31, 2008. If a Participant incurs a Separation from Service before January 1, 2005, such Participant (or his Beneficiary) shall receive his benefits under this Plan in a cash lump sum payment within ninety (90) days from the date that benefits are paid, or commence to be paid, under the terms of the Retirement Plan, regardless of whether or not such benefits are paid, or commence to be paid, under the Retirement Plan before January 1, 2009.

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6.03Specified Employees. Notwithstanding anything in this Plan to the contrary, if the payment of any benefit under this Article VI would be subject to taxation under Code Section 409A because the timing of such payment is not delayed to the extent required under Code Section 409A for a Specified Employee upon his Separation from Service, then if the Participant is a Specified Employee, any such payment that the Participant would otherwise be entitled to receive during the first six (6) months following his Separation from Service shall be accumulated and paid, within ninety (90) days after the date that is six months following the date of his Separation from Service, or such earlier date upon which such amount can be paid or provided under Code Section 409A without being subject to such additional taxes and interest such as, for example, due to the death of Participant.

ARTICLE VIIPARTICIPANT’S RIGHTS AND NATURE OF PLAN

Benefits payable under the Plan shall be a general, unsecured obligation of the Company to be paid by the Company from its own general assets, and such payments shall not (a) impose any obligation upon the Retirement Plan; (b) be paid by the Retirement Plan; or (c) have any effect whatsoever upon the Retirement Plan or the payment of benefits under the Retirement Plan. No Participant or his Beneficiary shall have any title to or beneficial ownership in any assets which the Company may earmark to pay benefits hereunder.

No amounts in respect of such benefits are required to be set aside or held in trust, and no recipient of any benefits shall have any right to have the benefit paid out of any particular assets of the Company; provided, however, nothing herein shall be construed to prevent a transfer of funds to a grantor trust (pursuant to applicable Code provisions) for the purpose of paying any benefits under this Plan. Any grantor trust established by the Company for benefits under this Plan shall be subject to the claims of the Company’s general and unsecured creditors in the event that the Company becomes insolvent. The Company intends that any such grantor trust shall constitute an unfunded arrangement and thus not affect, in any way, the status of this Plan as an unfunded plan that is maintained to provide deferred compensation for a select group of management or highly compensated employees for purposes of Title I of the Act.

ARTICLE VIIIAMENDMENT AND DISCONTINUANCE

The Directors may, in their absolute discretion, from time to time, amend, suspend or terminate in whole or in part, and if terminated, reinstate any or all of the provisions of this Plan, except that no amendment, suspension or termination may apply so as to reduce the payment to any Participant (or Beneficiary) of any benefit under this Plan that was earned and accrued prior to the effective date of such amendment, suspension or termination, unless the particular Participant (or Beneficiary) consents to such reduction in writing.

Notwithstanding the immediately preceding paragraph, the Plan may be amended by the Directors at any time if required to ensure that the Plan satisfies the requirements of the Code for

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nonqualified deferred compensation plans including Code Section 409A and (a) with respect to Limited 415 Participants, is characterized as an “excess benefit plan” as described in Sections 3(36) and 4(b)(5) of the Act and (b) with respect to Participants other than Limited 415 Participants, is characterized as a “top-hat plan” of deferred compensation maintained for a select group of management or highly compensated employees as described in Sections 201(2), 301(a)(3), and 401(a)(1) of the Act. No such amendment for this exclusive purpose shall be considered prejudicial to the interest of a Participant or a Beneficiary hereunder.

The Directors may delegate to an officer of the Company or Occidental Petroleum Corporation, the authority to execute an amendment to the Plan that has been approved by the Directors.

Upon termination of the Plan, distribution of benefits shall be made to Participants and Beneficiaries, as applicable, in the manner and at the time described in the Plan, unless one of the following termination events occurs, in which case, all such amounts shall be distributed in a lump sum upon termination, or upon the earliest date allowable under Code Section 409A: (1) the Company’s termination and liquidation of the Plan within twelve (12) months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court; (2) the Company’s termination and liquidation of the Plan pursuant to irrevocable action taken by the Company within the thirty (30) days preceding or twelve (12) months following a change in control event (within the meaning of Code Section 409A), provided that all agreements, methods, programs, and other arrangements sponsored by the Company that are aggregated under Code Section 409A are terminated and liquidated with respect to each Participant or Beneficiary who experiences the change in control event; or (3) the Company’s termination and liquidation of the Plan, provided that (a) the termination and liquidation does not occur proximate to a downturn in the financial health of the Company, (b) the Company terminates and liquidates all agreements, methods, programs, and other arrangements sponsored by the Company that would be aggregated under Code Section 409A if the same Participant had deferrals of compensation under all of the agreements, methods, programs, and other arrangements sponsored by the Company that are terminated and liquidated, (c) no payments in liquidation of the Plan are made within twelve (12) months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan other than payments that would have been payable absent the termination and liquidation, (d) all payments are made within twenty-four (24) months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan and (e) the Company does not adopt a new plan that would be aggregated with any terminated and liquidated plan under Code Section 409A if the same Participant participated in both plans, at any time within three (3) years following the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan.

ARTICLE IXCLAIMS PROCEDURE

9.01Filing a Claim. A Participant or his authorized representative may file a claim for benefits under the Plan (hereafter, referred to as a “Claimant”). Any claim must be in writing and

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submitted to the Committee at such address as may be specified from time to time. Claimants will be notified in writing of approved claims, which will be processed as claimed. A claim is considered approved only if its approval is communicated in writing to the Claimant.

9.02Denial of Claim. In the case of the denial of a claim respecting benefits paid or payable with respect to a Participant, a written notice will be furnished to the Claimant within 90 days of the date on which the claim is received by the Committee. If special circumstances (such as for a hearing) require a longer period, the Claimant will be notified in writing, prior to the expiration of the 90-day period, of the reasons for an extension of time; provided, however, that no extensions will be permitted beyond 90 days after the expiration of the initial 90-day period.

9.03Reasons for Denial. A denial or partial denial of a claim will be dated and signed by the Committee and will clearly set forth:

(a)the specific reason or reasons for the denial;

(b)specific reference to pertinent Plan provisions on which the denial is based;

(c)a description of any additional material or information necessary for the Claimant to perfect the claim and an explanation of why such material or information is necessary; and

(d)an explanation of the procedure for review of the denied or partially denied claim set forth below, including the claimant’s right to bring a civil action under Section 502(a) of the Act following an adverse benefit determination on review.

9.04Review of Denial. Upon denial of a claim, in whole or in part, the Claimant or his duly authorized representative will have the right to submit a written request to the Committee for a full and fair review of the denied claim by filing a written notice of appeal with the Committee within 60 days of the receipt by the Claimant of written notice of the denial of the claim. A Claimant or the Claimant’s authorized representative will have, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Claimant’s claim for benefits and may submit issues and comments in writing. The review will take into account all comments, documents, records, and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.

If the Claimant fails to file a request for review within 60 days of the denial notification, the claim will be deemed abandoned and the Claimant precluded from reasserting it. If the Claimant does file a request for review, his request must include a description of the issues and evidence he deems relevant. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.

9.05Decision Upon Review. The Committee will provide a prompt written decision on review to the Claimant. If the claim is denied on review, the decision shall set forth:

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(a)the specific reason or reasons for the adverse determination;

(b)specific reference to pertinent Plan provisions on which the adverse determination is based;

(c)a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Claimant’s claim for benefits; and

(d)a statement describing any voluntary appeal procedures offered by the Plan and the Claimant’s right to obtain the information about such procedures, as well as a statement of the Claimant’s right to bring an action under Section 502(a) of the Act.

A decision will be rendered no more than 60 days after the Committee’s receipt of the request for review, except that such period may be extended for an additional 60 days if the Committee determines that special circumstances (such as for a hearing) require such extension. If an extension of time is required, written notice of the extension will be furnished to the Claimant before the end of the initial 60-day period.

To the extent of its responsibility to review the denial of benefit claims, the Committee will have full authority to interpret and apply in its discretion the provisions of the Plan. The decision of the Committee will be final and binding upon any and all Claimants, including, but not limited to, the Participant and any other individual making a claim through him.

9.06Other Procedures. Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a Claimant a full and fair review of his claim and shall comply with applicable regulations under the Act.

9.07Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in this Article IX shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the Claimant has exhausted his remedies under this Section. In any such legal action, the Claimant may only present evidence and theories which the Claimant presented during the claims procedure. Any claims which the Claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a Claimant’s denied claim shall be limited to a determination of whether the denial was an abuse of discretion based on the evidence and theories the Claimant presented during the claims procedure. Any suit or legal action initiated by a Claimant under the Plan must be brought by the Claimant no later than one year following a final decision on the claim for benefits by the Committee. The one-year limitation on suits for benefits will apply in any forum where a Claimant initiates such suit or legal action.

9.08Effect of Committee Action. The Plan shall be interpreted by the Committee in accordance with the terms of the Plan and their intended meanings. However, the Committee shall

11

have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. The validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee has been granted discretionary authority under the Plan, the Committee’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If, due to errors in drafting, any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in its sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee may amend the Plan retroactively to cure any such ambiguity. This Section 9.08 may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee. All actions taken and all determinations made in good faith by the Committee shall be final and binding upon all persons claiming any interest in or under the Plan.

ARTICLE XMISCELLANEOUS

10.01Construction. The Plan is (a) an unfunded plan which is not intended to meet the qualification requirements of Code Section 401(a), and (b) designed to provide benefits to Participants after the Limitations are exceeded. All terms and provisions of the Plan shall be construed and constructed in accordance with such intent.

10.02Powers of the Company. The existence of outstanding and unpaid benefits under the Plan shall not affect in any way the right or power of the Employer to make or authorize any adjustments, recapitalization, reorganization or other changes in the Employer’s capital structure or in its business, or any merger or consolidation of the Employer, or any issue of bonds, debentures, common or preferred stock, or the dissolution or liquidation of the Employer, or any sale or transfer of all or any part of their assets or business, or any other act or corporate proceeding, whether of a similar character or otherwise.

10.03Beneficiary Designations. The Beneficiary designation for a Participant shall be the same as his Beneficiary designation under the Retirement Plan. If no valid Beneficiary designation exists at the time of the Participant’s death under the Retirement Plan, then the designation of a Beneficiary will follow the default provisions of the Retirement Plan if the Participant is a participant in the Retirement Plan at the time of his death.

In the event an Eligible Employee, upon becoming a Participant, is not a participant in the Retirement Plan, he may file with the Committee (or its delegate) a designation of one or more Beneficiaries to whom benefits otherwise payable to the Participant shall be made prior to the complete distribution of his benefits under the Plan. Such a Beneficiary designation shall be on the form prescribed by the Committee and shall be effective when received and accepted by the Committee. A Participant who is not a participant in the Retirement Plan may, from time to time,

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revoke or change his Beneficiary designation by filing a new designation form with the Committee. The last valid designation received by the Committee shall be controlling; provided, however, that no Beneficiary designation, or change or revocation thereof, shall be effective unless received prior to the Participant’s death, and shall not be effective as of a date prior to its receipt or if the Participant is a participant in the Retirement Plan at the time of his death.

If no valid Beneficiary designation exists at the time of the Participant’s death under the foregoing provisions of this Section 10.03 or if no designated Beneficiary under this Plan survives the Participant, or if such designation conflicts with applicable law, benefits shall be paid to the Participant’s surviving lawful spouse, if any. If there is no surviving spouse, then payment of benefits shall be made to the executor or administrator of the Participant’s estate, or if there is no administration on Participant’s estate, in accordance with the laws of descent and distribution. If the Committee is in doubt as to the right of any person to receive such amount, it may direct that the amount be paid into any court of competent jurisdiction in an interpleader action, and such payment shall be a full and complete discharge of any liability or obligation under the Plan to the full extent of such payment.

10.04Limitation of Rights. Nothing in this Plan shall be construed to:

(a)Except with respect to Limited 415 Participants, give any individual who is an Employee any right to be a Participant unless and until such person has been designated as such by the Committee;

(b)Give any Participant any rights, other than as an unsecured general creditor of the Employer, with respect to any benefits accrued under the Plan until such amounts are actually distributed to him;

(c)Limit in any way the right of the Employer to terminate a Participant’s Employment with the Employer;

(d)Give a Participant or any other person any interest in any fund or in any specific asset of the Employer;

(e)Give a Participant or any other person any interests or rights other than those of an unsecured general creditor of the Employer;

(f)Be evidence of any agreement or understanding, express or implied, that the Employer will employ a Participant in any particular position, at any particular rate of remuneration, or for any particular time period; or

(g)Create a fiduciary relationship between the Participant and the Directors, Employer and/or Committee.

10.05Distribution due to Qualified Domestic Relations Order. A distribution may be allowed for a “qualified domestic relations order” (“QDRO”) as described in Code Section 414(p). The Committee shall establish procedures to determine whether any domestic relations order

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submitted to the Committee is a QDRO and to administer distributions under any valid QDROs. If the Committee, in its discretion, determines a domestic relations order to be a QDRO, the Committee shall direct payment hereunder as it deems necessary to comply with such QDRO.

10.06Nonalienation of Benefits. No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same will be void and without effect. No right or benefit hereunder shall in any manner be liable for or subject to any debts, contracts, liabilities or torts of the person entitled to such benefits. The previous two sentences shall not preclude (a) the Participant from designating a Beneficiary to receive any benefit payable hereunder upon his death or (b) the executors, administrators, or other legal representatives of the Participant or his estate from assigning any rights hereunder to the person or persons entitled thereto.

10.07Facility of Payments. If the Committee determines that any person entitled to payment under the Plan is physically or mentally incompetent to receive such payment, the Committee shall direct the payment to the legal guardian or other personal representative of such person for the use and benefit of such person. If the Committee for any reason is unable to determine with reasonable certainty the proper person to pay pursuant to the immediately preceding sentence, the Committee may direct that any amounts due hereunder be paid into a court of competent jurisdiction in an interpleader proceeding for purposes of being directed by such court as to the proper disposition of such amounts. Any such payment shall be a full and complete discharge of any liability or obligation under the Plan.

10.08Withholding of Taxes. Participant hereby acknowledges and agrees that, as a result of any (a) deferral under this Plan or (b) payment received under this Plan, the Participant is solely responsible for any and all (i) federal, state and local income taxes and (ii) FICA and Medicare taxes ordinarily paid by Participant as an Employee. The Employer is hereby authorized to withhold from any amount payable hereunder any applicable withholding taxes and to take such other action as may be necessary or desirable, in the opinion of the Employer, to satisfy all obligations for the withholding and payment of such taxes.

10.09Adoption of Plan by Affiliated Entity. Any Affiliated Entity may adopt the Plan with the consent of the Directors or the Committee, effective as of the date specified therein. Any Employer, other than the Company, which has adopted the Plan shall not be responsible for the administration of the Plan.

10.10Waiver. No term or condition of this Plan shall be deemed to have been waived, nor shall there be an estoppel against the enforcement of any provision of this Plan, except by written instrument of the party charged with such waiver or estoppel. No such written waiver shall be deemed a continuing waiver unless specifically stated therein, and each such waiver shall operate only as to the specific term or condition waived and shall not constitute a waiver of such term or condition for the future or as to any act other than that specifically waived.

10.11Notice. Any notice required or permitted to be given under this Plan shall be sufficient if in writing and delivered via telecopier, messenger, or courier with appropriate proof of receipt, or sent by U.S. registered or certified or registered mail, return receipt requested, to the appropriate

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person or entity at the address last furnished by such person or entity. Such notice shall be deemed given as of the date of delivery to the recipient or, if delivery is made by U.S. mail, as of the date shown on the receipt for registration or certification.

10.12Severability. In the event that any provision of the Plan is declared invalid in a final decree or order issued by a court of competent jurisdiction, such declaration shall not affect the validity of the other provisions of the Plan which shall remain in full force and effect.

10.13Gender, Tense and Headings. Whenever the context requires, words of the masculine gender used herein shall include the feminine and neuter, and words used in the singular shall include the plural. The words “hereof,” “hereunder,” “herein,” and similar compounds of the word “here” shall refer to the entire Plan and not to any particular term or provision of the Plan. Headings of Articles and Sections, as used herein, are inserted solely for convenience and reference and shall not affect the meaning, interpretation or scope of the Plan.

10.14Governing Law. The Plan shall be subject to and governed by the laws of the State of Texas (other than its laws relating to choice of laws), except to the extent preempted by the Act, the Code or other controlling federal law.

[Signature page follows.]

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IN WITNESS WHEREOF, Anadarko Petroleum Corporation has caused this amended and restated Plan to be adopted and executed by its duly authorized officer effective as of the Effective Date.

ANADARKO PETROLEUM CORPORATION

By:    /s/ Darin S. Moss    

Name: /s/ Darin S. Moss    

Title:    Vice President    

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Anadarko Retirement Restoration Plan
Schedule A

This Schedule A forms a part of the Anadarko Retirement Restoration Plan, as amended from time to time (the “Plan”). The provisions of this Schedule A shall apply only to those Participants who are named herewith.

Supplemental Benefits for Robert A. Walker, Jr.

Plan Supplemental Benefit

If Mr. Walker remains employed by the Company at least until February 20, 2012 (attainment of age 55), then the benefit payable, as described in Section 5.01 of the Plan, shall be determined such that his aggregate benefits under the Retirement Plan and the Plan, and any successors thereto (collectively, the “Pension Plans”), are equal to the aggregate benefits to which he would have been entitled under the Pension Plans, if his years of Credited Service (as such term is defined in the Retirement Plan) with the Company (but not his age) were increased by eight (“Retiree Supplemental Benefit”). The Retiree Supplemental Benefit payable under this paragraph shall be paid at the same time or times as Mr. Walker’s benefit under the Plan.

Retiree Medical and Dental Supplemental Benefit

If Mr. Walker remains employed by the Company at least until February 20, 2012 (attainment of age 55), then Mr. Walker’s benefits under the Company’s retiree medical and dental plans shall be determined as if his years of service with the Company were increased by eight (“Medical Supplemental Benefit”). Upon his Separation from Service, he will be entitled to receive a lump sum payment under the Plan with the present value being computed by discounting to Mr. Walker’s date of termination, the projected Company paid retiree medical and dental premiums from his date of termination through February 20, 2022 (attainment of age 65) (i.e., the value of the Company subsidized portion of retiree medical and dental benefits) using a discount rate that is equivalent to the interest rate used to determine lump sum distributions under the Plan. For purposes of the aforementioned present value calculation, such calculation shall be performed by an accredited and certified actuarial firm, as designated by the Company. The Medical Supplemental Benefit payable under this paragraph shall be paid at the same time or times as Mr. Walker’s benefit under the Plan.

If, at the time of Mr. Walker’s termination of employment, the Company no longer provides subsidized pre-65 retiree medical and dental benefits, then the aforementioned lump sum payment will not be made. If, at the time of Mr. Walker’s termination of employment, Mr. Walker is otherwise eligible for subsidized retiree medical and dental benefits, then the aforementioned lump sum payment will not be made.

Schedule A-1

EX-10.38

Exhibit 10.38

Anadarko Petroleum Corporation

Deferred Compensation Plan

Amended and Restated effective as of December 31, 2019

Table of Contents

Page

ARTICLE 1 - DEFINITIONS    1

1.1“Account”    1

1.2“Administrator”    1

1.3“Annual Retainer Fees”    1

1.4“Base Pay”    1

1.5“Base Pay Deferral Election Period”    2

1.6“Beneficiary”    2

1.7“Board”    2

1.8“Bonus”    2

1.9“Change of Control”    2

1.10“Code”    4

1.11“Company”    4

1.12“Compensation Committee”    4

1.13“Contingent Beneficiary”    4

1.14“Director”    4

1.15“Director Compensation”    4

1.16“Director Compensation Deferral Election Period”    4

1.17“Disabled” or “Disability”    4

1.18“Effective Date”    4

1.19“Eligible Employee”    5

1.20“ERISA”    5

1.21“Key Employee”    5

1.22“Meeting Fees”    5

1.23“Participant”    5

1.24“Plan”    5

1.25“Plan Year”    5

1.26“Retirement”    6

1.27“Section 16 Officer”    6

1.28“Separation from Service”    6

1.29“Unforeseeable Emergency”    6

1.30“Valuation Date”    6

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ARTICLE 2 - PARTICIPATION    6

2.1Participation    6

2.2Cessation of Active Participation    6

ARTICLE 3 - DEFERRAL ELECTIONS    7

3.1Deferral Agreement    7

3.2Election to Defer Base Pay    7

3.3Election to Defer Bonus    7

3.4Election to Defer Director Compensation    8

3.5Timing of Election to Defer    8

3.6Election of Payment Schedule and Form of Payment    8

ARTICLE 4 - PARTICIPANT ACCOUNT    11

4.1Individual Accounts    11

ARTICLE 5 - INVESTMENT OF CONTRIBUTIONS    11

5.1Investment Options    11

5.2Adjustment of Accounts    11

5.3RESERVED    12

ARTICLE 6 - RIGHT TO BENEFITS    12

6.1Vesting    12

6.2Death    12

6.3Disability    13

ARTICLE 7 - DISTRIBUTION OF BENEFITS    13

7.1Amount of Benefits    13

7.2Method and Timing of Distributions    13

7.3Unforeseeable Emergency    13

7.4Cashouts of Minimal Interests    14

7.5Distribution to a Key Employee    14

ARTICLE 8 - AMENDMENT AND TERMINATION    14

8.1Amendment by Company    14

8.2Retroactive Amendments    15

8.3Special Plan and Deferral Election Amendments    15

8.4Plan Termination    15

8.5Distribution Upon Termination of the Plan    16

ARTICLE 9 - THE TRUST    16

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9.1Establishment of Trust    16

9.2Grantor Trust    16

9.3Investment of Trust Funds    16

9.4Participants’ Rights under a Trust    17

ARTICLE 10 - MISCELLANEOUS    17

10.1Unsecured General Creditor of the Company    17

10.2Limitation of Rights    17

10.3The Company’s Liability    17

10.4Satisfaction of Benefit Obligation    17

10.5Spend-thrift Provision    18

10.6Incapacity of Participant or Beneficiary    18

10.7Waiver    19

10.8Notices    19

10.9Tax Withholding    19

10.10Governing Law    20

10.11Intention to Comply with Code Section 409A    20

ARTICLE 11 - PLAN ADMINISTRATION    20

11.1Powers and Responsibilities of the Administrator    20

11.2Interpretation of the Plan    21

11.3Claims and Review Procedures    21

11.4Plan Administrative Costs    21

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PURPOSE

The Anadarko Petroleum Corporation Deferred Compensation Plan (the “Plan”) was originally established effective as of January 1, 2005, amended and restated effective as of January 1, 2012, and is hereby amended and restated effective as of December 31, 2019. The purpose of the Plan is to permit eligible employees and non-employee directors to defer receipt of certain compensation into a subsequent tax year which would otherwise be payable to them in the then-current tax year.

The Plan is intended to be a “plan which is unfunded and is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA and shall be implemented and administered in a manner consistent therewith. The Plan is also intended to (i) be exempt from the participation and vesting, funding, and fiduciary responsibility requirements of Title I of ERISA and (ii) qualify for simplified reporting under the U.S. Department of Labor Regulation Section 2520.104-23, as may be amended from time to time.

Effective as of December 31, 2019, the plan is closed to additional deferrals.

ARTICLE 1 - DEFINITIONS

Pronouns used in the Plan are in the masculine gender but include the feminine gender unless the context clearly indicates otherwise. Wherever used herein, the following terms have the meanings set forth below, unless a different meaning is clearly required by the context:

1.1 “Account” means an account established by the Administrator for the purpose of recording amounts credited on behalf of each Participant under the Plan, and any income, expenses, gains, losses or distributions included thereon. The Account shall be a bookkeeping entry only and shall be utilized solely as a device for the measurement and determination of the amounts to be paid to each Participant pursuant to the Plan.

1.2 “Administrator” means the Vice President, Human Resources, of Occidental Petroleum Corporation and delegates operating under the authority of the Vice President, Human Resources, including authorized third-party service providers, except that for all matters (including, without limitation, interpretation of the Plan) directly relating to participation, claims or benefits associated with individuals who are then Directors or Section 16 Officers, “Administrator” shall mean the Executive Compensation Committee of the Board of Directors of Occidental Petroleum Corporation, effective as of August 8, 2019.

1.3 “Annual Retainer Fees” means the annual fees (other than Meeting Fees) paid to a Director by the Company for service on the Board or committee(s) of the Board, including the Board retainer, lead director retainer, committee chair and member retainers and any other forms of retainer paid to a Director for service on the Board.

1.4 “Base Pay” means base compensation per payroll period paid by the Company to an Eligible Employee (including amounts which the Eligible Employee could have received in cash had he not elected to contribute to an employee benefit plan maintained by the Company),

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excluding overtime pay, bonuses, employee benefits, added premiums, differentials, components of foreign service assignments, and any other form of incentive compensation.

1.5 “Base Pay Deferral Election Period” means, with respect to each Plan Year, a period established by the Administrator that ends before the commencement of such Plan Year. For example, with respect to the Plan Year that begins on January 1, 2015, the Administrator may establish a Base Pay Deferral Election Period of any duration during the preceding Plan Year provided such period ends no later than December 31, 2014. If the Administrator takes no action to establish a Base Pay Deferral Election Period with respect to a particular Plan Year, then the Base Pay Deferral Election Period for such Plan Year shall begin on December 1 and end on December 31 of the preceding Plan Year.

1.6 “Beneficiary” means the persons, trusts, estates or other entities designated under Section 6.2 to receive benefits under the Plan upon the death of a Participant. “Contingent Beneficiary” means the persons, trusts, estates or other entities designated under Section 6.2 to receive benefits under the Plan upon the death of a Participant and in the event that the designated Beneficiary predeceases a Participant.

1.7 “Board” means the Board of Directors of Anadarko Petroleum Corporation.

1.8 “Bonus” means the bonus otherwise payable currently to a Participant for the Plan Year under the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, or any predecessor or successor plans thereto, or any other incentive or bonus arrangement implemented after the Effective Date by the Company if the Company designates payments under such program or arrangement as being Bonuses which may be deferred pursuant to this Plan.

1.9 “Change of Control” means that a Change of Control of the Company shall be deemed to have occurred on the date as of the first day any one or more of the following conditions shall have been satisfied:

(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (D) any acquisition pursuant to a transaction which complies with clauses (i), (ii) or (iii) of Section 1.9(c); or

2

(b) Individuals who, as of January 1, 2010, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to January 1, 2010 whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(c) Consummation by the Company of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of assets of another entity (a “Business Combination”), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than sixty percent (60%) of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, twenty percent (20%) or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination, and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(d) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company. Notwithstanding the foregoing provisions of this Section 1.9 or any provision of this Plan to the contrary, to the extent that any payment or acceleration of payment of any amount under the Plan is subject to, and not exempt under, Code Section 409A, then the determination of whether a Change of Control has occurred hereunder as affecting the payment, or timing of payment, of such

3

amount shall be made within the meaning of such term as set forth in Code Section 409A to the extent inconsistent with the foregoing provisions of this definition, as determined in the discretion of the Administrator.

1.10 “Code” means the Internal Revenue Code of 1986, as amended from time to time. All references herein to any Section of the Code shall include any successor provision thereto and the Treasury Regulations and other authority issued under such Section by the appropriate governmental authority.

1.11 “Company” means Anadarko Petroleum Corporation and its wholly owned subsidiaries, unless the context requires otherwise (such as, for example, in Section 1.9 where the term “Company” shall refer solely to Anadarko Petroleum Corporation).

1.12 “Compensation Committee” means the Compensation and Benefits Committee of the Board, the composition of which may change from time to time.

1.13 “Contingent Beneficiary” shall have the definition set forth in Section 1.6.

1.14 “Director” means a non-employee member of the Board.

1.15 “Director Compensation” means Annual Retainer Fees and Meeting Fees.

1.16 “Director Compensation Deferral Election Period” means, with respect to each Plan Year, a period established by the Administrator that ends before the commencement of such Plan Year. For example, with respect to the Plan Year that begins on January 1, 2015, the Administrator may establish a Director Compensation Deferral Election Period of any duration during the preceding Plan Year provided such period ends no later than December 31, 2014. If the Administrator takes no action to establish a Director Compensation Deferral Election Period with respect to a particular Plan Year, then the Director Compensation Deferral Election Period for such Plan Year shall begin on December 1 and end on December 31 of the preceding Plan Year.

1.17 “Disabled” or “Disability” means a Participant shall be deemed to have become permanently disabled if the Participant (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under a disability plan or an accident and health plan maintained by the Company, if applicable.

1.18 “Effective Date” means January 1, 2012, the effective date of this amendment and restatement of the Plan.

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1.19 “Eligible Employee” means an employee of the Company who is paid on the Company’s U.S. payroll and (i) is “a member of a select group of management or highly compensated employees” (within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA) and (ii) is designated by the Company in its complete discretion as being an Eligible Employee for purposes of the Plan. An employee who does not satisfy these criteria is an “Ineligible Employee.”

1.20 “ERISA” means the Employee Retirement Income Security Act of 1974, as may be amended from time to time. All references herein to any Section of ERISA shall include any successor provision thereto and the regulations and other authority issued under such Section by the appropriate governmental authority.

1.21 “Key Employee” means a Participant who is a “specified employee” as defined in Code Section 409A. For purposes of this definition, a “specified employee” under Code Section 409A is an employee who, as of the date of his Separation from Service, is a “key employee” (within the meaning of Code Section 416(i) without regard to paragraph 5 thereof relating to beneficiaries) of the Company or any entity which is considered to be a single employer with the Company under Code Section 414(b) or 414(c) (the “Controlled Group”). A Participant shall be a Key Employee if the Participant is (i) an officer of the Company having annual compensation greater than $165,000 for 2012 (and as indexed thereafter under Code Section 416(i)), (ii) a 5-percent (5%) owner of the Company, or (iii) a 1-percent (1%) owner of the Company having annual compensation of more than $150,000, at any time during the twelve (12) month period ending on December 31, but only if a Controlled Group member has any stock that is publicly traded on an established securities market or otherwise. A Participant will be considered to be a Key Employee for the period April 1 through March 31 following such December 31 determination. The Company may apply an alternative method to identify Key Employees in accordance with Code Section 409A, provided that the alternative method (i) is reasonably designed to include all Key Employees, (ii) is an objectively determinable standard, and (iii) results in either all employees or no more than 200 employees being identified as Key Employees as of any date.

1.22 “Meeting Fees” means fees paid to a Director for attendance at meetings of the Board or meetings of the Board’s committees.

1.23 “Participant” means any Eligible Employee or any Director who becomes a participant in the Plan pursuant to Article 2. An individual who becomes a Participant as provided in the preceding sentence shall remain a Participant until he no longer has an undistributed Account balance under the Plan.

1.24 “Plan” means the Anadarko Petroleum Corporation Deferred Compensation Plan, as amended and restated as set forth herein, and as it may be further amended from time to time.

1.25 “Plan Year” means the twelve (12) consecutive month period beginning January 1st and ending December 31st of any given year.

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1.26 “Retirement” means, in the case of an Eligible Employee who is eligible to retire under the Anadarko Retirement Plan (the “Anadarko Plan”), his Separation from Service; provided, however, that the Eligible Employee has, as of such date, both attained age fifty-five (55) and been credited with at least five (5) years of Credited Service as that term is defined under the Anadarko Plan. Retirement means, in the case of an Eligible Employee who is eligible to retire under the Kerr-McGee Corporation Retirement Plan (the “KMG Plan”), his Separation from Service; provided, however, that the Eligible Employee has, as of such date, both attained age fifty-two (52) and been credited with at least ten (10) years of Credited Service as that term is defined under the KMG Plan. Retirement means, in the case of a Director, Separation from Service from the Board after the first to occur of: (a) the Director having attained age sixty-five (65), (b) the Director having completed ten (10) years of service as a Director, or (c) the Director having attained both age fifty-five (55) and completed five (5) years of service as a Director. A Director’s total years of service as a Director as of any date shall be determined by dividing his total completed full months of service as a Director by twelve (12).

1.27 “Section 16 Officer” means an Eligible Employee who is subject to the requirements of Section 16 of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

1.28 “Separation from Service” means a “separation from service” of an Eligible Employee or Director within the meaning of Code Section 409A.

1.29 “Unforeseeable Emergency” means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse, the Participant’s Beneficiary, or a dependent (as defined in Code Section 152(a)) of the Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstance arising as a result of events beyond the control of the Participant.

1.30 “Valuation Date” means each business day of the Plan Year and such other date(s) as designated by the Company.

ARTICLE 2 - PARTICIPATION

2.1 Participation. Each Eligible Employee and Director shall become a Participant in the Plan by executing a deferral agreement in accordance with the provisions of Article 3.

2.2 Cessation of Active Participation. In the event that (i) the service on the Board of a Participant who is a Director terminates, or (ii) a Participant who is an Eligible Employee incurs a Separation from Service for any reason, such Director or Eligible Employee, as applicable, may not make deferral elections under Article 3 and any deferral election presently in effect for such Director or Eligible Employee shall terminate immediately; however, any compensation subject to a valid deferral election under the Plan and earned with respect to any period preceding the effective time of such cessation of the right to defer compensation hereunder shall be deferred pursuant to such election, even if such crediting of such amount to his Account occurs after such effective time. In the event that a Participant

6

becomes an Ineligible Employee for any reason other than Separation from Service (including, without limitation, by reason of the Company, in its sole discretion, designating a Participant as an Ineligible Employee), such Participant may not make deferral elections under Article 3 immediately after the Participant becomes an Ineligible Employee; however, any irrevocable deferral election made prior to the time that the Participant became an Ineligible Employee shall remain in effect, unless voided as stated herein in connection with a subsequent Separation from Service. At the discretion of the Company or the Administrator, an individual who has become a Participant in the Plan shall cease to be entitled to defer compensation hereunder at the time and in such manner as determined by the Company or the Administrator to be necessary or appropriate to comply with applicable law or regulations or to coordinate with other benefit plans of the Company; provided, however, that such cessation is permitted and consistent with the requirements of Code Section 409A. Upon any termination of a Participant’s right to defer compensation hereunder, the provisions of Section 7.2 shall continue to apply to such Participant’s Account.

ARTICLE 3 - DEFERRAL ELECTIONS

3.1 Deferral Agreement. Each Eligible Employee and Director may elect to defer compensation amounts otherwise payable to him currently for a Plan Year by executing a deferral agreement in accordance with (a) rules and procedures established by the Administrator, (b) the provisions of this Article 3, and (c) Code Section 409A. The deferral agreement may separately specify for each discrete type of compensation (e.g., Base Pay, Bonus, Director Compensation, or individual components of each) the whole number percentage multiple (in one percent (1%) increments and subject to the percentage limitations otherwise described herein) that the Participant elects to defer, the payment schedule and form of payment of the deferred amount.

A new deferral agreement must be executed in a timely manner (as set forth in this Article 3) for each Plan Year during which the Eligible Employee or Director elects to defer compensation. An Eligible Employee or Director who does not execute a deferral agreement in a timely manner shall be deemed to have elected zero deferrals for such Plan Year.

A deferral agreement may be changed or revoked at any time during the respective election periods specified in Section 3.5. A deferral agreement becomes irrevocable at the close of the respective election period. An irrevocable deferral election may be subsequently modified only as permitted in Section 7.2.

3.2 Election to Defer Base Pay. An Eligible Employee may elect to defer Base Pay for a Plan Year in an amount not exceeding seventy-five percent (75%) of Base Pay. A Participant who is first designated as an Eligible Employee after the first day of the calendar month preceding the calendar month in which a Base Pay Deferral Election Period commences with respect to a Plan Year may not elect to defer his Base Pay for the Plan Year to which such period relates but may elect to defer his Base Pay for subsequent Plan Years.

3.3 Election to Defer Bonus. An Eligible Employee may elect to defer up to one hundred percent (100%) of his Bonus for a Plan Year, subject to any limitation that may be established

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by the Administrator and specified on the deferral agreement. A Participant who is first designated as an Eligible Employee after January 1st of a Plan Year may not elect to defer his Bonus for that Plan Year but may elect to defer his Bonus for subsequent Plan Years.

3.4 Election to Defer Director Compensation. A Director may elect to defer up to one hundred (100%) of his Director Compensation for a Plan Year. An individual who first becomes a Director on or after the first day of a Director Compensation Deferral Election Period with respect to a Plan Year may not elect to defer his Director Compensation for the Plan Year to which such period relates but may elect to defer his Director Compensation for subsequent Plan Years.

3.5 Timing of Election to Defer. Each Eligible Employee who desires (and who is eligible pursuant to Section 3.2) to defer Base Pay otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator and within the Base Pay Deferral Election Period with respect to such Plan Year. A deferral agreement that is timely and properly executed in accordance with the preceding sentence shall be irrevocable as of the last day of the applicable Base Pay Deferral Election Period. Each Eligible Employee who is eligible to defer a Bonus which may be earned with respect to services performed during a Plan Year pursuant to Section 3.3 and who desires to defer such Bonus must execute a deferral agreement in accordance with the rules and procedures established by the Administrator (but not later than December 31st immediately preceding such Plan Year except that if the plan or arrangement providing for such Bonus is “performance-based compensation based on services performed over a period of at least 12 months” (as described in Code Section 409A(a)(4)(B)(iii)), then such deferral election must be executed no later than the Bonus Deferral Deadline Date (as hereinafter defined) (provided that (a) the Eligible Employee performs services continuously from the later of the beginning of the performance period or the date the performance criteria are established through the date such election is made and (b) such compensation has not become readily ascertainable as of the date of such election), and such election will be irrevocable as of the earlier of the Bonus Deferral Deadline Date or the date upon which such compensation has become readily ascertainable). For purposes of the preceding sentence, the term “Bonus Deferral Deadline Date” means, with respect to a particular Bonus, the date six (6) months before the end of the performance period over which the Bonus is earned, or such earlier date as the Administrator may require in its sole discretion.

A Director who desires (and who is eligible pursuant to Section 3.4) to defer his Director Compensation otherwise payable during a Plan Year must execute a deferral agreement in accordance with the procedures established by the Administrator and within the Director Compensation Deferral Election Period with respect to such Plan Year. A deferral agreement that is timely and properly executed in accordance with the preceding sentence shall be irrevocable as of the last day of the applicable Director Compensation Deferral Election Period.

3.6 Election of Payment Schedule and Form of Payment. At the time an Eligible Employee or Director completes a deferral agreement provided by the Administrator, the Eligible

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Employee or Director may separately elect for each type of compensation being deferred (i.e., Base Pay, Bonus, Director Compensation, or individual components of each) the following items: (i) the date of distribution or commencement of distribution of each deferred amount, (ii) the form of payment in which each deferred amount will be distributed (e.g., lump sum or annual installments), and (iii) if applicable and as may be provided by the Administrator, whether the amount distributed will be in cash or a combination of cash. Subject to the provisions of Article 7, an Eligible Employee or Director may elect to receive distribution of his deferred amount in a single lump sum or annual installment distributions over a period certain not exceeding fifteen (15) years. If the Participant should elect installment payments over a designated time period, each installment payment shall be considered a separate payment for purposes of Code Section 409A.

The portion of the Participant’s Account that has been earned and vested as of January 1, 2010 (as well as any subsequent earnings, expenses, gains and losses attributed to such balance) (“Pre-2010 Account”) shall be distributed as follows:

(a) If the Participant’s Separation from Service occurs before he becomes eligible for Retirement, notwithstanding any other election, his distribution shall be made as follows:

(1) If the Participant initially elected to be paid upon his Separation from Service following Retirement, his distribution shall be made in a lump-sum payment no later than ninety (90) days after the date of his Separation from Service; or

(2) If the Participant initially elected to be paid upon an identified and specific date that is at least three (3) years after the date the deferral agreement was effective, then if payment has not already commenced, his distribution shall be made or shall commence on such identified and specific date; or

(3) If the Participant initially elected to be paid upon the earlier of (A) Separation from Service following Retirement or (B) an identified and specific date that is at least three (3) years after the date the deferral agreement was effective, then if payment has not already been made or commenced, his distribution shall be made in a lump sum payment no later than ninety (90) days after the date of his Separation from Service.

(b) If the Participant’s Separation from Service occurs after he becomes eligible for Retirement, then the distribution or commencement of distribution shall be one of the following options as previously elected by the Participant:

(1) Separation from Service; or

(2) an identified and specific date that is at least three (3) years after the date the deferral agreement was executed; or

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(3) the earlier of (A) Separation from Service or (B) an identified and specific date that is at least three (3) years after the date the deferral agreement was executed. This option (3) provides that the date of distribution specified in the deferral agreement will be honored unless a Separation from Service intervenes before the scheduled date of distribution, in which case payment will be made, in the form originally elected by the Participant, not later than the date that is ninety (90) days after the Separation from Service date.

The portion of the Participant’s Account that is earned and vested on and after January 1, 2010 (as well as any subsequent earnings, expenses, gains and losses attributed to such balance) (“Post-2009 Account”) shall be distributed as follows:

(c) If the Participant’s Separation from Service occurs before he becomes eligible for Retirement, notwithstanding any other election, his distribution shall be made as follows:

(1) If the Participant initially elected to be paid upon his Separation from Service following Retirement, his distribution shall be made in a lump-sum payment no later than ninety (90) days after the date of his Separation from Service; or

(2) If the Participant initially elected to be paid upon an identified and specific date that is at least one (1) year after the date the deferral agreement was effective, then if payment has not already commenced, his distribution shall be made or shall commence on such identified and specific date; or

(3) If the Participant initially elected to be paid upon the earlier of (A) Separation from Service following Retirement or (B) an identified and specific date that is at least one (1) year after the date the deferral agreement was effective, then if payment has not already been made or commenced, his distribution shall be made in a lump sum payment no later than ninety (90) days after the date of his Separation from Service.

(d) If the Participant’s Separation from Service occurs after he becomes eligible for Retirement, then the distribution or commencement of distribution shall be one of the following options as previously elected by the Participant:

(1) Separation from Service; or

(2) an identified and specific date which is at least one (1) year after the date the deferral agreement was executed; or

(3) the earlier of (A) Separation from Service or (B) an identified and specific date which is at least one (1) year after the date the deferral agreement was executed. This option (3) provides that the date of distribution specified in the deferral agreement will be honored unless a Separation from Service

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intervenes before the scheduled date of distribution, in which case payment will be made, in the form originally elected by the Participant, not later than the date that is ninety (90) days after the Separation from Service date.

In addition, regardless of whether Retirement is attained by the Participant, he may elect a “Change of Control Override.” A Change of Control Override election provides that the date and form of distribution specified in the deferral agreement will be honored unless a Change of Control intervenes before the scheduled date of distribution, in which case, payment will be made in a single lump sum within ninety (90) days after the effective date of the Change of Control without regard to whether Participant has incurred a Separation from Service. Notwithstanding any provision in the Plan to the contrary, for purposes of effectuating an accelerated payment hereunder pursuant to a Change of Control Override, the term “Change of Control” shall mean a Change of Control (as defined in Section 1.9 of the Plan) but only to the extent that the event causing the Change of Control qualifies under Code Section 409A(a)(2)(A)(v).

ARTICLE 4 - PARTICIPANT ACCOUNT

4.1 Individual Accounts. The Administrator will establish and maintain an Account for each Participant that reflects deferrals made pursuant to Article 3, together with earnings, expenses, gains and losses that are attributable to investments of such Account as provided in Article 5. The amount a Participant elects to defer in accordance with Article 3 shall be credited to the Participant’s Account at the time the amount subject to the deferral election would otherwise have been payable to the Participant but for his deferral election. The Administrator will establish and maintain such other accounts and records as it determines, in its discretion, to be reasonably required or appropriate to discharge its duties under the Plan.

ARTICLE 5 - INVESTMENT OF CONTRIBUTIONS

5.1 Investment Options. The amount credited to a Participant’s Account shall be treated as invested in the investment options as designated for this purpose by the Administrator. Such investment options may be different for Eligible Employees, Section 16 Officers and Directors, as determined by the Administrator in its discretion.

5.2 Adjustment of Accounts. The amount credited to a Participant’s Account shall be adjusted for hypothetical investment earnings or losses in an amount equivalent to the earnings or losses reported by the investment options selected by the Participant or Beneficiary from among the investment options provided in Section 5.1. A Participant may, in accordance with rules and procedures established by the Administrator, change the investments to be used for the purpose of calculating future hypothetical investment adjustments to the Participant’s Account or to future Participant deferrals, which election change shall be effective as of the Valuation Date coincident with or next following notice to the Administrator. The Account of each Participant shall be adjusted as of each Valuation Date to reflect: (a) the hypothetical investment earnings and/or losses described above; (b) Participant deferrals; and (c) distributions or withdrawals from the Account.

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5.3 RESERVED.

ARTICLE 6 - RIGHT TO BENEFITS

6.1 Vesting. At all times, each Participant has a one hundred percent (100%) nonforfeitable interest in all amounts credited to his Account. Notwithstanding the foregoing or any provision of the Plan to the contrary, if otherwise provided pursuant to a Company plan or program for which a benefit has been deferred under the Plan, a Participant may be subject to certain “claw back” or forfeiture of benefits in certain circumstances, in which case a Participant’s Account may be reduced in an amount necessary to satisfy such “claw back” or forfeiture.

6.2 Death. Notwithstanding any prior election regarding the form or timing of his distribution, the balance or remaining balance credited to a Participant’s Account shall be paid to his Beneficiary in a single lump-sum cash payment within ninety (90) days following the Participant’s death. If multiple Beneficiaries have been designated by the Participant, each Beneficiary shall receive a single lump-sum cash payment of his specified portion of the Participant’s Account balance within such ninety (90) day period. If the Participant has not specified percentages for multiple Beneficiaries, his Account will be divided and distributed to them on a per capita basis.

A Participant may designate a Beneficiary or Beneficiaries, or change any prior designation of Beneficiary or Beneficiaries in accordance with rules and procedures established by the Administrator (including, but not limited to, the right to require the consent of a Participant’s spouse in the event the spouse is not named as the sole primary Beneficiary).

If a designated Beneficiary predeceases a Participant, the amount apportioned to that designated Beneficiary shall be payable to the designated Contingent Beneficiary, if any. If a Beneficiary dies within thirty (30) days of the date the Participant dies, the Beneficiary shall be considered to have predeceased the Participant for purposes of this Section 6.2.

If the Administrator finds either that there is no designated Beneficiary for all or a portion of a Participant’s Account, or that the designated Beneficiary and any Contingent Beneficiary for all or a portion of a Participant’s account have predeceased the Participant, the amount in question shall be paid as follows: (a) if the Participant leaves a surviving spouse, the entire Account balance shall be paid to the surviving spouse, and (b) only if the Participant leaves no surviving spouse, the entire Account balance shall be paid (i) first to the executor or administrator of the Participant’s estate, or (ii) if there is no administration of his estate, to the Participant’s heirs at law, as determined by the Administrator.

Notwithstanding the preceding provisions of this Article 6 and to the extent not prohibited by state or federal law, if a Participant is divorced from his spouse and, at the time of his death, is not remarried to the person from whom he was divorced, any designation of such divorced spouse shall be null and void unless the contrary is expressly stated in a writing that is filed by the Participant with the Administrator and accepted by the Administrator. The amount that would otherwise have been paid to such divorced spouse shall instead be

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paid to the persons specified in accordance with the applicable provisions of this Article 6 as if such divorced spouse did not survive the Participant.

If the Administrator is in doubt as to the right of any person to receive any amount hereunder, the Administrator, in its discretion, may direct that the entire Account balance be paid into any court of competent jurisdiction in an interpleader action, and such payment shall be a full and complete discharge of any liability or obligation under the Plan to the full extent of such payment.

6.3 Disability. Notwithstanding any prior election regarding the form or timing of his distribution, the balance or remaining balance credited to a Participant’s Account shall be paid to the Participant in a single lump-sum cash payment within ninety (90) days following the date the Participant is determined to be Disabled.

ARTICLE 7 - DISTRIBUTION OF BENEFITS

7.1 Amount of Benefits. The amount credited to a Participant’s Account as determined under Articles 4, 5 and 6 shall determine and constitute the basis for the value of benefits payable to the Participant under the Plan.

7.2 Method and Timing of Distributions. Subject to Sections 7.3 and 7.4, distributions under the Plan shall be made at the time and in the manner provided in Section 3.6. If allowed by the Administrator, a Participant may elect to further delay the payment date for a minimum period of sixty (60) months from the originally scheduled date of payment, provided that such election to delay payment (a) is made at least twelve (12) months before a scheduled date of payment and (b) is not effective until at least twelve (12) months after the date on which the election is made. A re-deferral election must be made in accordance with procedures and rules established by the Administrator, which shall be construed and administered in accordance with Code Section 409A. The Participant may, at the same time the date of payment is re-deferred, change the form of payment provided that such change in the form of payment does not effectuate an acceleration of payment. Notwithstanding any provision contained herein to the contrary, a distribution made to a Key Employee due to his Separation from Service (for any reason except due to his death) shall not be made before the date which is six (6) months after the date the Key Employee has a Separation from Service unless otherwise permitted under Code Section 409A, such as in the event of his death.

7.3 Unforeseeable Emergency. A Participant may request a distribution due to an Unforeseeable Emergency. The request must be in writing and must be submitted to the Administrator along with evidence that the circumstances constitute an Unforeseeable Emergency. The Administrator has the discretion to require whatever evidence it deems necessary to determine whether a distribution is warranted. Whether a Participant has incurred an Unforeseeable Emergency will be determined by the Administrator on the basis of the relevant facts and circumstances in its sole discretion, but, in no event, will an Unforeseeable Emergency be deemed to exist if the hardship can be relieved: (a) through reimbursement or compensation by insurance or otherwise, (b) by liquidation of the

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Participant’s assets to the extent such liquidation would not itself cause severe financial hardship, or (c) by cessation of deferrals under the Plan. A distribution due to an Unforeseeable Emergency must be limited to the amount reasonably necessary to satisfy the emergency need and may also include any amount necessary to pay any federal, state or local income taxes or penalties that are reasonably anticipated to result from the distribution. The distribution will be made in the form of a single lump-sum cash payment without regard to any prior distribution election. Any distribution under this Section 7.3 shall be deducted from the Participant’s Account balance as of the date of the distribution.

7.4 Cashouts of Minimal Interests. If the amount credited to the Participant’s Account does not exceed the current dollar limitation under Code Section 402(g)(1)(B) ($17,000 in 2012, as adjusted under the Code in future years, or such higher dollar amount as Treasury Regulations may establish for cashouts of minimal interests under Code Section 409A), at the time he has a Separation from Service, and such Participant is not a Key Employee, the Company reserves the right to pay such amount to the Participant in accordance with the requirements of Code Section 409A in a single lump-sum cash payment within ninety (90) days following such Separation from Service, regardless of whether the Participant (i) had made a different election regarding time or form of payment or (ii) was receiving installment payments at the time of Separation from Service. In the case of a Key Employee, such cashout payment shall not be made before the date that is at least six (6) months from the date of his Separation from Service or such earlier date upon which such amount can be paid under Code Section 409A without being subject to taxation thereunder.

7.5 Distribution to a Key Employee. Notwithstanding any provision of the Plan to contrary, any lump sum or installment payment distribution payable to a Participant who is a Key Employee due to his Separation from Service (for any reason except due to his death) shall not be made before the date that is six (6) months after the date of his Separation from Service.

ARTICLE 8 - AMENDMENT AND TERMINATION

8.1 Amendment by Company. The Company reserves the right to amend the Plan through action of the Board. An amendment must be in writing and executed by an officer authorized to take such action. Each amendment shall not be effective prior to approval by the Board in its resolution, unless necessary to comply with applicable laws or regulations. No amendment can directly or indirectly deprive any current or former Participant or Beneficiary of all or any portion of his Account balance that has accrued as of the date of such amendment. Effective August 8, 2019, in addition to amendments made by the Board, the Chief Executive Officer of the Company or other officer designated by the Board (the “Authorized Officer”), may approve, adopt and execute any amendment to the Plan that is necessary for purposes of legal compliance, to clarify ambiguities in the Plan document, and to simplify non-material administrative processes, as the Authorized Officer may, in his best judgment, so determine; provided that the Authorized Officer may not terminate the Plan. The Authorized Officer may delegate to another officer of the Company or Occidental Petroleum Corporation the

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authority to execute an amendment to the Plan that has been approved jointly by the Authorized Officers.

Notwithstanding the preceding paragraph of this Section 8.1, the Plan may be amended if required to ensure that the Plan is characterized as a “top-hat plan” of deferred compensation maintained for a select group of management or highly compensated employees as described under ERISA Sections 201(2), 301(a)(3), and 401(a)(1), or to conform the Plan to the requirements of ERISA for “top-hat plans” or the requirements of the Code for deferred compensation plans including Code Section 409A. No such amendment for this exclusive purpose shall be considered prejudicial to the interest of a Participant or a Beneficiary hereunder.

8.2 Retroactive Amendments. An amendment made by the Company in accordance with Section 8.1 may be made effective on a date prior to the first day of the Plan Year in which it is adopted if such amendment is necessary or appropriate to enable the Plan to satisfy the applicable requirements of the Code, ERISA or to any other change in federal law or to any regulations or ruling thereunder. Any retroactive amendment by the Company shall be subject to the provisions of Section 8.1.

8.3 Special Plan and Deferral Election Amendments. Notwithstanding Sections 8.1 or 8.2 or any other provision of the Plan or a deferral election agreement to the contrary, the Company has reserved the unilateral right and discretion to amend the Plan and a Participant’s deferral elections hereunder to the extent necessary to comply with Code Section 409A, or to be exempt from the application of Code Section 409A, to the maximum extent permitted under Code Section 409A.

8.4 Plan Termination. The Plan has been adopted with the intention and expectation that it will be continued indefinitely. The Company, however, reserves the right to terminate the Plan at any time without any liability for any such discontinuance or termination.

In the event of the termination of the Plan, no additional vesting shall accrue on a Participant’s behalf after the termination date. In accordance with Code Section 409A, termination of the Plan shall not, by itself, create a distribution event.

Upon termination of the Plan, distribution of benefits shall be made to Participants and Beneficiaries in the same manner and at the same time as described in the Plan, unless one of the following termination events occurs, in which case, all such amounts shall be distributed in a lump sum upon termination, or upon the earliest date allowable under Code Section 409A:

(a) the Company’s termination and liquidation of the Plan within twelve (12) months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. Section 503(b)(1)(A);

(b) the Company’s termination and liquidation of the Plan pursuant to irrevocable action taken by the Company within the thirty (30) days preceding or twelve (12) months

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following a change of control event (within the meaning of Code Section 409A), provided that all agreements, methods, programs, and other arrangements sponsored by the Company or an affiliated entity that are aggregated under Code Section 409A are terminated and liquidated with respect to each Participant that experiences the change in control event; or

(c) the Company’s termination and liquidation of the Plan, provided that (1) the termination and liquidation does not occur proximate to a downturn in the financial health of the Company; (2) the Company terminates and liquidates all agreements, methods, programs, and other arrangements sponsored by the Company that would be aggregated under Code Section 409A if the same Participant had deferrals of compensation under all of the agreements, methods, programs, and other arrangements sponsored by the Company that are terminated and liquidated; (3) no payments in liquidation of the Plan are made within twelve (12) months of the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan other than payments that would have been payable absent the termination and liquidation; and (4) the Company does not adopt a new plan that would be aggregated with any terminated and liquidated plan under Code Section 409A if the same Participant participated in both plans, at any time within three (3) years following the date the Company takes all necessary action to irrevocably terminate and liquidate the Plan.

8.5 Distribution Upon Termination of the Plan. Upon termination of the Plan, no further contributions that have not accrued as of the termination date shall be made under the Plan. Each Participant’s Account at the time of termination shall continue to be governed by the terms of the Plan until fully distributed in accordance with the terms of the Plan.

ARTICLE 9 - THE TRUST

9.1 Establishment of Trust. The Company may, but is not required to, establish a trust, or use an existing trust, to hold amounts which the Company may contribute from time to time to correspond to some or all amounts credited to Participants under Section 4.1. If the Company elects to establish a trust, the provisions of Sections 9.2 and 9.3 shall be operative.

9.2 Grantor Trust. The Company may establish a trust, or use an existing trust, between the Company and a trustee pursuant to a separate written trust agreement. Any such trust shall be created as a grantor trust under the Code Sections 671-678, and the establishment of the trust shall not cause the Participant to realize current income on amounts contributed to the trust. In the event that the Company establishes such a trust or uses an existing trust, the Company shall be under no obligation to place assets in such trust to secure the Company’s payment obligations under the Plan.

9.3 Investment of Trust Funds. Any amounts contributed to a trust described in this Article 9 may be invested by the trustee in accordance with the provisions of the trust agreement and the instructions of the Administrator or the Company. Trust investments need not reflect the hypothetical investments selected by Participants under Section 5.1 for the purpose of

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adjusting Account balances, and the investment results of the trust shall not affect the hypothetical investment adjustments to Accounts under the Plan.

9.4 Participants’ Rights under a Trust. The assets of any trust hereunder shall be held for the benefit of the Participants in accordance with the terms of the Plan and the trust agreement. The assets of the trust shall remain subject to the claims of the general creditors of the Company, and the rights of the Participants to the amounts in the trust shall be limited in the event that the Company becomes insolvent. No Participant or Beneficiary shall have any preferred claim to, or any beneficial ownership interest in, any assets of the trust fund.

ARTICLE 10 - MISCELLANEOUS

10.1 Unsecured General Creditor of the Company. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Company as the result of participating in the Plan. For purposes of the payment of benefits under the Plan, any and all of the Company’s assets shall be, and shall remain, the general, unpledged, unrestricted assets of the Company, and as such, shall remain subject to the claims of the general creditors of the Company. The Company’s obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay compensation in the future.

10.2 Limitation of Rights. Nothing in this plan shall be construed to:

(a) Give any individual who is employed by the Company any right to be a Participant unless and until such person is selected under the terms of the Plan;

(b) Give any Participant any rights, other than as an unsecured general creditor of the Company;

(c) Limit in any way the right of the Company to terminate an Eligible Employee’s employment;

(d) Give a Participant or any other person any interest in any trust, fund or in any specific asset of the Company; or

(e) Be evidence of any agreement or understanding, express or implied, that the Company will employ a Participant in any particular position, at any particular rate of remuneration, or for any particular time period.

10.3 The Company’s Liability. The Company’s liability for the payment of benefits under the Plan shall be defined only by the Plan and by the deferral agreements, and form and timing of payment elections, as entered into between a Participant and the Company under the Plan. The Company shall have no obligation or liability to a Participant under the Plan except as provided by the Plan.

10.4 Satisfaction of Benefit Obligation. The Company may, but is not obligated, to purchase an annuity or other insurance/financial product to satisfy the payment of benefit obligations

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for some or all of the Participants under the Plan. In the event that such an annuity or other product is utilized and a Participant or his Beneficiary has received the benefits entitled under the Plan from such annuity or other product, then such benefit obligation under the Plan shall be considered satisfied. Any annuity or other product used to provide funding under the Plan shall be an asset of the Company, and no Participant shall have any beneficial ownership interest in such asset of the Company.

In order to meet its contingent obligations under the Plan, the Company shall not set aside any assets or otherwise create any type of fund in which any Participant (or any person claiming under such Participant) has an interest other than that of an unsecured general creditor of the Company or that would provide any Participant, or any person claiming under such Participant, with a legally enforceable right to priority over any general creditor of the Company in the event that the Company becomes insolvent.

10.5 Spend-thrift Provision. No amount payable or to become payable from the Plan will be subject to: (a) anticipation or assignment by any person entitled to receive benefits under the Plan; (b) attachment by, interference with, or control of any creditor of any person entitled to receive benefits under the Plan; or (c) being taken or reached by any legal or equitable process in satisfaction of any debt or liability of any person entitled to receive benefits under the Plan. Any attempted conveyance, transfer, assignment, mortgage, pledge, or encumbrance of the Plan, any part of it or any interest in it, by any person entitled to receive benefits under the Plan prior to distribution will be void, regardless of whether that conveyance, transfer, assignment, mortgage, pledge, or encumbrance is intended to be effective before or after any distribution of benefits under the Plan. In addition, the Administrator shall not recognize any conveyance, transfer, assignment, mortgage, pledge or encumbrance by any person entitled to receive benefits under the Plan, and shall not pay any amount to any creditor or assignee of such person for any cause whatsoever. However, this Section 10.5 shall not affect the provisions of Section 10.1 regarding the claims of general creditors of the Company.

In the event that any Participant’s or Beneficiary’s benefits hereunder are attempted to be garnished or attached by order of any court, the Company, in its discretion, may bring an action or a declaratory judgment in a court of competent jurisdiction to determine the proper recipient of the benefits to be paid under the Plan.

10.6 Incapacity of Participant or Beneficiary. If the Administrator determines, in its discretion, that any Participant or Beneficiary to whom a payment is payable under the Plan is unable to care for his affairs because of illness or accident or is under a legal disability, any payment due (unless a prior claim therefore shall have been made by a duly appointed legal representative), at the discretion of the Administrator, may be paid to the spouse, child, parent, sibling of such Participant or Beneficiary or to any person whom the Administrator has determined has incurred expense for such Participant or Beneficiary. In the event that a guardian, conservator or other person legally vested with the care of any person receiving a benefit under the Plan is appointed by a court of competent jurisdiction, payments shall be made to such guardian, conservator or other person, provided that proper proof of

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appointment is furnished in a form and manner acceptable to the Administrator. Any payment made in accordance with this Section 10.6 shall be a complete discharge of the obligations of the Company under the Plan.

10.7 Waiver. No term or condition of the Plan shall be deemed to have been waived, nor shall there be an estoppel against the enforcement of any provision of the Plan, except by written instrument of the party charged with such waiver or estoppel. No such written waiver shall be deemed a continuing waiver unless specifically stated therein, and each such waiver shall operate only as to the specific term or condition waived and shall not constitute a waiver of such term or condition for the future or as to any act other than that specifically waived.

10.8 Notices. Any notice or other communication in connection with the Plan shall be deemed delivered in writing if addressed as provided below and if either actually delivered at said address or, in the case of a letter, five (5) business days shall have elapsed after the same shall have been deposited in the U.S. mails, first-class postage prepaid and registered or certified:

(a) The Company or Administrator — If the notice is sent to the Company or Administrator, it must be sent to the then-current corporate headquarters address of the Company, provided that the envelope includes “Attn: Benefits Department — Human Resources”; or

(b) Participant — The mailing or electronic address of the Participant as reflected in the then-current records of the Company. Each Participant is responsible for ensuring that the Company or Administrator has the Participant’s current mailing address under the procedure for updating mailing addresses utilized by the Company or Administrator.

10.9 Tax Withholding. The Company shall have the right to deduct from all payments or deferrals made under the Plan any tax required by law to be withheld. If the Company concludes that tax is owing with respect to any deferral or payment hereunder, the Company shall withhold such amounts from any payments due the Participant, as permitted by law, or otherwise make appropriate arrangements with the Participant or his Beneficiary for satisfaction of such obligation. A tax, for purposes of this Section 10.9 means any federal, state, local or any other governmental income tax, employment or payroll tax, excise tax, or any other tax or assessment that is owed with respect to amounts deferred (and any earnings thereon) and any payments made to Participants under the Plan.

With respect to deferred compensation elections under the Plan, the Company shall withhold the required share of FICA, FUTA and other applicable employment and payroll taxes from the other non-deferred compensation of an Eligible Employee who is a Participant. These required payroll taxes shall be withheld at the same time that the deferred compensation contributions are credited to his Account.

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10.10 Governing Law. The Plan will be construed, administered and enforced according to ERISA, the Code and other controlling federal law, and to the extent not preempted thereby, the laws of the State of Texas without regard to its conflicts of law principles.

10.11 Intention to Comply with Code Section 409A. The Plan is intended to comply with Code Section 409A and any ambiguous provision will be construed in a manner that is compliant with, or exempt from, the application of Code Section 409A. It is intended that since January 1, 2009, the Plan will comply with provisions of Code Section 409A and the final regulations and other authoritative guidance thereunder. It is also intended that during the period beginning January 1, 2005 and ending December 31, 2008, the Plan was operated in reasonable good faith compliance with the provisions of Code Section 409A and the interim authoritative guidance thereunder. If any provision of the Plan would cause a Participant to incur any additional tax or interest under Code Section 409A, the Company may reform such provision to comply with Code Section 409A to the maximum extent permitted under Code Section 409A as determined by the Company.

ARTICLE 11 - PLAN ADMINISTRATION

11.1 Powers and Responsibilities of the Administrator. The Administrator has the full power, full discretion and the full responsibility to administer the Plan in all of its details, subject, however, to the applicable requirements of applicable law. The Administrator’s powers and responsibilities include, but are not limited to, the following:

(a) To make and enforce such rules and procedures as it deems necessary or proper for the efficient administration of the Plan;

(b) To interpret the Plan, its interpretation thereof in good faith to be final and conclusive on all persons claiming benefits under the Plan;

(c) To decide all questions concerning the Plan and the eligibility of any person to participate in the Plan;

(d) To administer the claims and review procedures specified in Section 11.3, including determining all facts pertaining to a claim;

(e) To compute the amount of benefits which will be payable to any Participant, former Participant or Beneficiary in accordance with the provisions of the Plan;

(f) To determine the person or persons to whom such benefits will be paid;

(g) To authorize the payment of benefits;

(h) To comply with the reporting and disclosure requirements of Part I. of Subtitle B of Title I of ERISA;

(i) To appoint such agents, counsel, accountants, and consultants as may be required to assist in administering the Plan;

20

(j) By written instrument, to allocate and delegate its responsibilities hereunder to designated persons or entities, including without limitation, to employees of the Company; and

(k) To address and resolve any and all matters that may arise with regard to the Plan and its administration.

11.2 Interpretation of the Plan. The Administrator shall interpret, construe and construct the Plan, including correcting any defect, supplying any omission or reconciling any inconsistency. The Administrator shall have all powers necessary or appropriate to implement and administer the terms and provisions of the Plan, including the power to make findings of fact. The determination of the Administrator as to the proper interpretation, construction, or application of any term or provision of the Plan shall be final, binding, and conclusive with respect to all Participants and other interested persons.

11.3 Claims and Review Procedures. Claims for Plan benefits and reviews of appeals of benefit claims arising under the Plan that have been denied or modified are to be processed in accordance with written Plan claims procedures established by the Administrator and adopted by the Company. The Plan’s claims and appeal procedures shall be established and administered in accordance with the applicable requirements for such procedures under ERISA.

11.4 Plan Administrative Costs. Unless otherwise determined by the Administrator, all reasonable costs and expenses (including legal, accounting, and employee communication fees) incurred by the Administrator in administering the Plan shall be paid by the Company.

21

IN WITNESS WHEREOF, the Company, by its duly authorized officer, has caused the amended and restated Plan to be adopted on this 27th day of December, 2019, to be effective as of December 31, 2019.

ANADARKO PETROLEUM CORPORATION

By:    /s/ Darin S. Moss    

Darin S. Moss    

Vice President, Human Resources

22

EX-21

EXHIBIT 21

LIST OF SUBSIDIARIES

The following is a list of the Registrant’s subsidiaries at December 31, 2019.

Name	Jurisdiction of Formation
Amarok Gathering, LLC	Delaware
Anadarko 20-25 Company	Cayman Islands
Anadarko 20-36 Company	Cayman Islands
Anadarko 20-47 Company	Cayman Islands
Anadarko 20-48 Company	Cayman Islands
Anadarko 20-49 Company	Cayman Islands
Anadarko Algeria Block 403 c/e Company	Cayman Islands
Anadarko Algeria Block 406B Company	Cayman Islands
Anadarko Algeria Company, LLC	Delaware
Anadarko Algeria Oil & Gas Company	Cayman Islands
Anadarko Brazil Investment I LLC	Delaware
Anadarko Brazil Investment II LLC	Delaware
Anadarko Colombia Company	Cayman Islands
Anadarko Consolidated Holdings LLC	Delaware
Anadarko DBMOS Operator, LLC	Delaware
Anadarko DJ Gas Processing LLC	Delaware
Anadarko DJ Oil Pipeline LLC	Delaware
Anadarko E&P Onshore LLC	Delaware
Anadarko Energy Services Company	Delaware
Anadarko Finance Company	Nova Scotia
Anadarko Gabon Company	Cayman Islands
Anadarko Gathering Company LLC	Delaware
Anadarko Ghana Mahogany-1 Company	Cayman Islands
Anadarko Global Funding 1 Company	Cayman Islands
Anadarko Guyana Company	Cayman Islands
Anadarko Holding Company	Utah
Anadarko International Energy Company	Delaware
Anadarko International O&G Company	Cayman Islands
Anadarko International Trading Corporation	Delaware
Anadarko Jordan Company	Delaware
Anadarko Kenya Company	Cayman Islands
Anadarko Land Corp.	Nebraska
Anadarko Mi Vida LLC	Delaware
Anadarko Midkiff/Chaney Dell BR Corp.	Delaware
Anadarko Midkiff/Chaney Dell LLC	Delaware
Anadarko Natural Gas Company LLC	Delaware
Anadarko New Zealand Company	Cayman Islands
Anadarko Offshore Holding Company, LLC	Delaware
Anadarko Offshore Well Containment Company LLC	Delaware
Anadarko OGC Company	Delaware
Anadarko Oil & Gas 5, LLC	Delaware
Anadarko Pecos Midstream LLC	Delaware
Anadarko Realty, LLC	Texas
Anadarko Rockies LLC	Delaware
Anadarko Royalty Holdings Company	Delaware
Anadarko Uintah Midstream, LLC	Delaware
Anadarko US Offshore LLC	Delaware
Anadarko USH1 Corporation	Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Anadarko Venezuela Company	Cayman Islands
Anadarko Venezuela LLC	Delaware
Anadarko Wattenberg Company, LLC	Delaware
Anadarko Wattenberg Oil Complex LLC	Delaware
Anadarko WCTP Company	Cayman Islands
Anadarko West Texas BR Corp.	Delaware
Anadarko West Texas LLC	Delaware
APC Aviation, Inc.	Delaware
APC International Holdings LLC	Delaware
APC Midstream Holdings, LLC	Delaware
APC Water Holdings 1, LLC	Delaware
Aventine LLC	New Mexico
Baseball Merger Sub 2, Inc.	Delaware
Bear Branch Exploration, LLC	Delaware
Big Island Trona Company	Delaware
Bitter Creek Coal Company	Utah
Bravo Pipeline Company	Delaware
Cain Chemical Inc.	Delaware
Chipeta Processing LLC	Delaware
Concord Petroleum Corporation	Panama
Conn Creek Shale Company	Delaware
D.S. Ventures, LLC	Texas
DBM Crude Services, LLC	Delaware
DBM Oil Services, LLC	Delaware
DBM Pipeline, LLC	Delaware
DBM Water Services, LLC	Delaware
Deerwood Exploration, LLC	Delaware
Delaware Basin Express, LLC	Delaware
Delaware Basin JV Gathering LLC	Delaware
Delaware Basin Midstream, LLC	Delaware
DMM Financial LLC	Delaware
Downtown Plaza II	Oklahoma
FLAG Development, LLC	Delaware
FP Westport Commodities Limited	United Kingdom
FP Westport GmbH	Switzerland
FP Westport Limited	United Kingdom
FP Westport LLC	Delaware
FP Westport Services LLC	Delaware
FP Westport Trading LLC	Delaware
Glenn Springs Holdings, Inc.	Delaware
Globrep Representaciones S.A.	Ecuador
GNB NGL Pipeline LLC	Delaware
Grand Bassa Tankers, Inc.	Delaware
Grupo OxyChem de Mexico, S.A. de C.V.	Mexico
Headwater II, LLC	Delaware
Houndstooth Resources, LLC	Texas
INDSPEC Chemical B.V.	The Netherlands
INDSPEC Chemical Corporation	Delaware
INDSPEC Chemical Export Sales, LLC	Delaware
INDSPEC Holding Corporation	Delaware
Ingleside Cogeneration GP 2, Inc.	Delaware
Ingleside Cogeneration GP, Inc.	Delaware
Ingleside Cogeneration Limited Partnership	Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Interore Trading Ltd.	Liberia
Interseqt, LLC	Delaware
Joslyn Partnership	Alberta, Canada
Kerr-McGee Corporation	Delaware
Kerr-McGee do Brasil Ltda.	Brazil
Kerr-McGee Gathering LLC	Colorado
Kerr-McGee Natural Gas Company, Inc.	Delaware
Kerr-McGee of Canada Northwest Ltd.	Alberta
Kerr-McGee Oil & Gas Onshore LP	Delaware
Kerr-McGee Shared Services Company LLC	Delaware
Kerr-McGee Stored Power Corporation	Nevada
Kerr-McGee U.K. Energy Corporation	Delaware
Kerr-McGee Worldwide Corporation	Delaware
KM BM-C-Seven Ltd.	Cayman Islands
KM International Insurance Ltd.	Bermuda
Laguna Petroleum, LLC	Texas
Liwa Oil & Gas Ltd.	Bermuda
Mariana Properties, Inc.	Delaware
Marico Exploration, Inc.	New Mexico
MC2 Technologies LLC	Delaware
MIGC LLC	Delaware
Miller Springs Remediation Management, Inc.	Delaware
Moncrief Minerals Partnership, L.P.	Texas
Mountain Gas Resources LLC	Delaware
Mountain Gas Transportation LLC	Delaware
Natural Gas Odorizing, Inc.	Oklahoma
New OPL, LLC	Delaware
NGL Ventures LLC	Delaware
Oakwood Exploration, LLC	Delaware
Occidental (Bermuda) Ltd.	Bermuda
Occidental (East Shabwa), LLC	Nevis
Occidental Advance Sale Finance, Inc.	California
Occidental Al Hosn, LLC	Delaware
Occidental Andina, LLC	Delaware
Occidental Angola Holdings Ltd.	Bermuda
Occidental Canada Holdings Ltd.	Nova Scotia
Occidental Chemical Asia, Limited	Japan
Occidental Chemical Belgium B.V.B.A.	Belgium
Occidental Chemical Chile Limitada	Chile
Occidental Chemical Corporation	New York
Occidental Chemical de Mexico, S.A. de C.V.	Mexico
Occidental Chemical Export Sales, LLC	Delaware
Occidental Chemical Far East Limited	Hong Kong
Occidental Chemical Holding Corporation	California
Occidental Chemical International, LLC	California
Occidental Chemical Investment (Canada) 1, Inc.	Delaware
Occidental Chile Investments, LLC	Delaware
Occidental Chile Minority Holder, LLC	Delaware
Occidental CIS Services, Inc.	Delaware
Occidental Colombia (Series G) Ltd.	Bermuda
Occidental Colombia (Series J) Ltd.	Bermuda
Occidental Colombia (Series K) Ltd.	Bermuda
Occidental Colombia (Series L) Ltd.	Bermuda

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Occidental Colombia (Series M) Ltd.	Bermuda
Occidental Colombia (Series N) Ltd.	Bermuda
Occidental Colombia (Series O) Ltd.	Bermuda
Occidental Condor Block LLA 39 Ltd.	Bermuda
Occidental Condor Block LLA 52 Ltd.	Bermuda
Occidental Condor, LLC	Delaware
Occidental Crude Sales, Inc. (Canada)	Delaware
Occidental Crude Sales, Inc. (International)	Delaware
Occidental Crude Sales, LLC (South America)	Delaware
Occidental de Colombia, LLC	Delaware
Occidental del Ecuador, Inc.	Nevis
Occidental Dolphin Holdings Ltd.	Bermuda
Occidental Energy Marketing, Inc.	Delaware
Occidental Energy Ventures LLC	Delaware
Occidental Exploradora del Peru Ltd.	Bermuda
Occidental Exploration and Production Company	California
Occidental Hafar, LLC	Delaware
Occidental International (Libya), Inc.	Delaware
Occidental International Corporation	Delaware
Occidental International Exploration and Production Company	California
Occidental International Holdings Ltd.	Bermuda
Occidental International Oil and Gas Ltd.	Bermuda
Occidental International Services, Inc.	Delaware
Occidental Joslyn GP 2 Co.	Nova Scotia
Occidental Latin America Holdings, LLC	Delaware
Occidental Libya Oil & Gas B.V.	The Netherlands
Occidental LNG (Malaysia) Ltd.	Bermuda
Occidental MENA Manager Ltd.	Bermuda
Occidental Middle East Development Company	Delaware
Occidental Midland Basin, LLC	Delaware
Occidental Mukhaizna, LLC	Delaware
Occidental of Abu Dhabi (Bab) Ltd.	Bermuda
Occidental of Abu Dhabi (Shah) Ltd.	Bermuda
Occidental of Abu Dhabi Ltd.	Bermuda
Occidental of Abu Dhabi, LLC	Delaware
Occidental of Bahrain Ltd.	Bermuda
Occidental of Bangladesh, Inc.	Delaware
Occidental of Colombia (Chipiron), Inc.	Nevis
Occidental of Colombia (Cosecha), Inc.	Nevis
Occidental of Colombia (Medina), Inc.	Nevis
Occidental of Colombia (Putumayo) Ltd.	Bermuda
Occidental of Colombia (Putumayo) Ltd.	Bermuda
Occidental of Colombia (Teca) Ltd.	Bermuda
Occidental of Dubai, Inc.	Nevis
Occidental of Iraq Holdings Ltd.	Bermuda
Occidental of Iraq, LLC	Delaware
Occidental of Oman, Inc.	Nevis
Occidental of Russia Ltd.	Bermuda
Occidental of South Africa (Offshore), Inc.	Nevis
Occidental of Yemen (Block 75), LLC	Delaware
Occidental Oil and Gas (Oman) Ltd.	Nevis
Occidental Oil and Gas Corporation	Texas
Occidental Oil and Gas International Inc.	Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Occidental Oil and Gas International, LLC	Delaware
Occidental Oil and Gas of Peru, LLC	Delaware
Occidental Oil and Gas Pakistan LLC	Nevis
Occidental Oil Asia Pte. Ltd.	Singapore
Occidental Oil Shale, Inc.	California
Occidental Oman (Block 27) Holdings Ltd.	Bermuda
Occidental Oman Block 51 Holding Ltd.	Bermuda
Occidental Oman Block 51, LLC	Delaware
Occidental Oman Block 65 Holding Ltd.	Bermuda
Occidental Oman Block 65, LLC	Delaware
Occidental Oman Block 72 Holding Ltd.	Bermuda
Occidental Oman Block 72, LLC	Delaware
Occidental Oman Gas Company LLC	Delaware
Occidental Oman Gas Holdings Ltd.	Bermuda
Occidental Oman North Holdings, Ltd.	Bermuda
Occidental Oriente Exploration and Production Ltd.	Cayman Islands
Occidental Overseas Holdings B.V.	The Netherlands
Occidental Peninsula II, Inc.	Nevis
Occidental Peninsula, LLC	Delaware
Occidental Permian Ltd.	Texas
Occidental Permian Manager LLC	Delaware
Occidental Permian Services, Inc.	Delaware
Occidental Peruana, Inc.	California
Occidental Petrolera del Peru (Block 101), Inc.	Nevis
Occidental Petrolera del Peru (Block 103), Inc.	Nevis
Occidental Petroleum (Pakistan), Inc.	Delaware
Occidental Petroleum Corporation	Delaware
Occidental Petroleum Corporation Political Action Committee	California
Occidental Petroleum de Venezuela, S.A.	Venezuela
Occidental Petroleum of Nigeria	Nigeria
Occidental Petroleum of Oman Ltd.	Nevis
Occidental Petroleum of Qatar Ltd.	Bermuda
Occidental Power Marketing, L.P.	Delaware
Occidental Power Services, Inc.	Delaware
Occidental PVC, LLC	Texas
Occidental Qatar Energy Company LLC	Delaware
Occidental Red Sea Development, LLC	Nevis
Occidental Research Corporation	California
Occidental Resource Recovery Systems, Inc.	California
Occidental Resources Company	Cayman Islands
Occidental Shah Gas Holdings Ltd.	Bermuda
Occidental South America Finance, LLC	Delaware
Occidental Specialty Marketing, Inc.	Delaware
Occidental Tower Corporation	Delaware
Occidental Transportation Holding Corporation	Delaware
Occidental West Texas Overthrust, Inc.	Texas
Occidental Yemen Ltd.	Bermuda
Occidental Yemen Sabatain, Inc.	Nevis
Oceanic Marine Transport Ltd.	Bermuda
OEVC Energy, LLC	Texas
OEVC Midstream Projects, LLC	Delaware
OLCV CE Holdings, ULC	British Columbia
OLCV CE US Holdings, Inc.	Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
OLCV Net Power, LLC	Texas
OLCV Services LLC	Delaware
OOG Partner LLC	Delaware
OOOI Chem Holdings, LLC	Delaware
OOOI Chem Sub, LLC	Delaware
OOOI Chemical International, LLC	Delaware
OOOI Chile Holder, LLC	Delaware
OOOI Ecuador Management, LLC	Delaware
OOOI Oil and Gas Sub, LLC	Delaware
OOOI South America Management, LLC	Delaware
Opcal Insurance, Inc.	Hawaii
OPM GP, Inc.	Delaware
OPM Holdco, LLC	Delaware
Oryx Crude Trading & Transportation, Inc.	Delaware
Overland Trail Transmission, LLC	Delaware
Oxy BridgeTex Limited Partnership	Texas
Oxy C & I Bulk Sales, LLC	Delaware
Oxy Cactus II, LLC	Texas
OXY Campus, LLC	Delaware
Oxy Canada Sales, Inc.	Delaware
Oxy Carbon Solutions, LLC	Texas
Oxy Carbon Storage, LLC	Delaware
Oxy Climate Ventures, Inc.	Delaware
Oxy Cogeneration Holding Company, Inc.	Delaware
Oxy Colombia Holdings, LLC	Delaware
OXY CV Pipeline LLC	Delaware
Oxy Delaware Basin Plant, LLC	Delaware
Oxy Delaware Basin, LLC	Texas
Oxy Dolphin E&P, LLC	Nevis
Oxy Dolphin Pipeline, LLC	Nevis
Oxy Energy Canada, Inc.	Delaware
Oxy Energy Services, LLC	Delaware
Oxy Expatriate Services, Inc.	Delaware
Oxy FFT Holdings, Inc.	Delaware
Oxy Holding Company (Pipeline), Inc.	Delaware
OXY Inc.	California
Oxy International Ventures Ltd.	Bermuda
Oxy Levelland Pipeline Company, LLC	Delaware
Oxy Levelland Terminal Company, LLC	Delaware
OXY Libya E&P Area 103 BR4 B.V.	The Netherlands
OXY Libya E&P Area 35 Ltd.	Bermuda
OXY Libya E&P Concession 103 Ltd.	Bermuda
OXY Libya E&P EPSA 102 B.V.	The Netherlands
OXY Libya E&P EPSA 1981 Ltd.	Bermuda
OXY Libya E&P EPSA 1985 Ltd.	Bermuda
OXY Libya Exploration, SPC	Cayman Islands
OXY Libya, LLC	Delaware
OXY Little Knife, LLC	Delaware
Oxy Low Carbon Ventures, LLC	Delaware
OXY LPG LLC	Delaware
Oxy LPG Terminal, LLC	Delaware
OXY Mexico Holdings I, LLC	Delaware
OXY Mexico Holdings II, LLC	Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
OXY Middle East Holdings Ltd.	Bermuda
Oxy Midstream Strategic Development, LLC	Delaware
OXY of Saudi Arabia Ltd.	Cayman Islands
OXY Oil Partners, Inc.	Delaware
Oxy Oleoducto SOP, LLC	Delaware
Oxy Overseas Services Ltd.	Bermuda
OXY PBLP Manager, LLC	Delaware
Oxy Permian Gathering, LLC	Delaware
Oxy Permian Plaza, LLC	Delaware
Oxy Petroleum de Mexico, S. de R.L. de C.V.	Mexico
Oxy Renewable Energy LLC	Texas
Oxy Salt Creek Pipeline LLC	Delaware
OXY Support Services, LLC	Delaware
Oxy Taft Hub, LLC	Texas
Oxy Technology Ventures, Inc.	Delaware
Oxy TL, LLC	Delaware
Oxy Transport I Company, LLC	Delaware
OXY Tulsa Inc.	Delaware
OXY USA Inc.	Delaware
OXY USA WTP LP	Delaware
Oxy Vinyls Canada Co.	Nova Scotia
Oxy Vinyls Export Sales, LLC	Delaware
Oxy Vinyls, LP	Delaware
OXY VPP Investments, LLC	Delaware
OXY West, LLC	Texas
Oxy Westwood Corporation	California
Oxy Y-1 Company	New Mexico
OXYCHEM (CANADA), INC.	Alberta, Canada
OxyChem do Brasil Ltda.	Brazil
OxyChem Ingleside Ethylene Holdings, Inc.	Delaware
Oxychem Shipping Ltd.	Malta
OxyChile Investments, LLC	Delaware
OxyCol Holder Ltd.	Bermuda
OXYMAR	Texas
Permian Basin Limited Partnership	Delaware
Permian VPP Holder, LP	Delaware
Permian VPP Manager, LLC	Delaware
Placid Oil, LLC	Delaware
Ramlat Oxy Ltd.	Bermuda
Rio de Viento, Inc.	Wyoming
Rodeo Midland Basin, LLC	Delaware
San Patricio Pipeline LLC	Delaware
Scanports Shipping, LLC	Delaware
Swiflite Aircraft Corporation	New Jersey
Transok Properties, LLC	Delaware
Troy Potter, Inc.	Texas
Turavent Oil GmbH	Switzerland
Tuscaloosa Holdings, Inc.	Delaware
Vintage Gas, Inc.	Oklahoma
Vintage Petroleum Argentina Ltd.	Cayman Islands
Vintage Petroleum Boliviana, Ltd.	Bermuda
Vintage Petroleum International Finance B.V.	The Netherlands
Vintage Petroleum International Holdings, LLC	Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Vintage Petroleum International Ventures, Inc.	Cayman Islands
Vintage Petroleum International, LLC	Delaware
Vintage Petroleum Italy, Inc.	Oklahoma
Vintage Petroleum South America Holdings, Inc.	Cayman Islands
Vintage Petroleum South America, LLC	Oklahoma
Vintage Petroleum Turkey, Inc.	Cayman Islands
Wamsutter Pipeline LLC	Delaware
Wardner Ranch, Inc.	Delaware
Western Gas Operating, LLC	Delaware
Western Gas Resources, Inc.	Delaware
Western Gas Wyoming, L.L.C.	Wyoming
Western Midstream Holdings, LLC	Delaware
WGR Asset Holding Company LLC	Delaware
WGR Canada, Inc.	New Brunswick
WGR Operating, LP	Delaware
Woodlands International Insurance Ltd.	Bermuda
YT Ranch LLC	Colorado

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Occidental Petroleum Corporation:

We consent to the incorporation by reference in the registration statement (No. 333-55404, 333-83124, 333-142705, 333-203801, 333-207413, 333-224691, 333-232928, and 333-235445) on Forms S-3 and S-8 of Occidental Petroleum Corporation of our reports dated February 27, 2020, with respect to the consolidated balance sheets of Occidental Petroleum Corporation as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes and financial statement schedule II, and the effectiveness of internal control over financial reporting as of December 31, 2019, which reports appear in the December 31, 2019 annual report on Form 10-K of Occidental Petroleum Corporation.

Our report refers to a change in the method of accounting for leases in 2019 due to the adoption of Accounting

Standards Codification Topic 842, Leases.

/s/ KPMG LLP

Houston, Texas

February 27, 2020

EX-23.2

Exhibit 23.2

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the (i) inclusion in the Occidental Petroleum Corporation (Occidental) Form 10-K for the year ended December 31, 2019, and the incorporation by reference in Occidental's registration statements (Nos.333-55404, 333-83124, 333-142705, 333-203801, 333-207413, 333-224691, 333-232928, and 333-235445) (the “Registration Statements”), including any amendments thereto, of references to our firm and to our letter dated February 5, 2020, relating to our review of the methods and procedures used by Occidental for estimating its oil and gas proved reserves (our “Letter”), (ii) filing of our Letter with the U.S. Securities and Exchange Commission as Exhibit 99.1 to the Form 10-K and (iii) incorporation by reference of our Letter in the Registration Statements.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 27, 2020

SUITE 800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    FAX (403) 262-2790

633 17TH STREET, SUITE 1700    DENVER, COLORADO 80202    TEL (303) 339-8110

EX-23.3

Exhibit 23.3

February 27, 2020

Occidental Petroleum Corporation

5 Greenway Plaza, Suite 110

Houston, TX 77046

CONSENT OF INDEPENDENT PETROELUM ENGINEERS

To the Board of Directors

Occidental Petroleum Corporation:

We hereby consent to the (i) inclusion in the Occidental Petroleum Corporation (“Occidental”) Form 10-K for the year ended December 31, 2019 (“Form 10-K”), and the incorporation by reference in Occidental’s registration statements (Nos. 333-55404, 333-83124, 333-142705, 333-203801, 333-207413, 333-224691, 333-232928 and 333-235445) (the “Registration Statements”), including any amendments thereto, of references to our firm and to our Procedures and Methods Review Letter dated February 27, 2020, relating to our review of the methods and procedures used by Occidental for estimating certain of its oil and gas proved reserves (our “Letter”), (ii) filing of our Letter with the U.S. Securities and Exchange Commission as Exhibit 99.2 to the Form 10-K and (iii) incorporation by reference of our Letter in the Registration Statements.

Miller and Lents, Ltd. has no financial interest in Occidental or in any of its affiliated companies or subsidiaries and is not to receive any such interest as payment for such letter. Miller and Lents, Ltd. also has no director, officer, or employee employed or otherwise connected with Occidental. We are not employed by Occidental on a contingent basis.

/s/ Miller and Lents, Ltd.

Texas Registered Engineering Firm No. F-1442

EX-31.1

EXHIBIT 31.1

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

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

I, Vicki Hollub, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  February 27, 2020

/s/ Vicki Hollub

Vicki Hollub

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

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

I, Cedric W. Burgher, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 27, 2020

/s/ Cedric W. Burgher

Cedric W. Burgher

Senior Vice President and

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO

18 U.S.C. § 1350,

AS ADOPTED PURSUANT TO

§ 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Occidental Petroleum Corporation (the “Company”) for the fiscal period ended December 31, 2019, as filed with the Securities and Exchange Commission on February 27, 2020 (the “Report”), Vicki Hollub, as Chief Executive Officer of the Company, and Cedric W. Burgher, as Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of her or his knowledge:

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

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

/s/ Vicki Hollub
Name:	Vicki Hollub
Title:	President and Chief Executive Officer
Date:	February 27, 2020

/s/ Cedric W. Burgher
Name:	Cedric W. Burgher
Title:	Senior Vice President and Chief Financial Officer
Date:	February 27, 2020

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

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

EX-99.1

Occidental Petroleum Corporation

January [ ], 2011

Page 1

EXHIBIT 99.1

OCCIDENTAL PETROLEUM CORPORATION

Process Review

of the

Estimated

Future Proved Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

and

Certain Economic Interests

Derived Through Certain Production Sharing Contracts

LEGACY OXY PROPERTIES

SEC Parameters

As of

December 31, 2019

/s/ Guale Ramirez

Guale Ramirez, P.E.

TBPE License No. 48318

President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

February 5, 2020

Occidental Petroleum Corporation

5 Greenway Plaza, Suite 110

Houston, Texas 77046

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has conducted a process review of the methods and analytical procedures utilized by the engineering and geological staff of Occidental Petroleum Corporation (Occidental) for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as of December 31, 2019, based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The results of our third party reserves process review, completed on December 26, 2019 and presented herein, were prepared for public disclosure by Occidental in filings made with the SEC in accordance with the disclosure requirements set forth under Section 229.1202(a)(8) of the SEC regulations. The properties that we reviewed are classified as LEGACY OXY properties. The effective date of this report is February 5, 2020.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties are appropriate for the purpose thereof, and comply with the SEC regulations as of December 31, 2019. Ryder Scott has not been engaged to render an opinion as to the reasonableness of the proved reserves quantities reported by Occidental.

Properties Reviewed

The proved reserves reviewed herein are attributable to the leasehold and royalty interests of Occidental in certain properties located in the United States in the states of New Mexico and Texas and derived through Occidental’s economic interest as defined in contractual arrangements for certain properties located in the Middle East.

The properties reviewed herein were selected by Occidental. Ryder Scott and Occidental concur that these properties are a valid representation of Occidental’s total net proved reserves portfolio as of December 31, 2019. Based on the estimates prepared by Occidental, the portion of total company net liquid and net gas reserves reviewed by us are expressed as a percentage and presented in summary form on the following page. At Occidental’s request and provided by Occidental, we have also presented the portion of the total company net proved reserves reviewed by us on a barrel of oil equivalent (BOE) basis.

SUITE 800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    FAX (403) 262-2790

633 17TH STREET, SUITE 1700    DENVER, COLORADO 80202    TEL (303) 339-8110

Occidental Petroleum Corporation

February 5, 2020

Page 2

Percentage of Total Company Estimated Net Reserves

Reviewed by Ryder Scott

SEC Parameters

Occidental Petroleum Corporation

As of December 31, 2019

	Oil/Condensate	NGL	Total Liquid Hydrocarbons	Gas	Equivalent BOE
Total Proved Developed	20.8%	9.6%	17.8%	4.1%	13.7%
Total Proved Undeveloped	24.7%	14.6%	21.8%	8.9%	18.2%
Total Company Proved	21.7%	10.9%	18.8%	5.2%	14.8%

The net liquid hydrocarbons reviewed are comprised of oil, condensate and natural gas liquids (NGL) and are based on standard 42 gallon barrels. All net gas volumes reviewed are based on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.Reserves reviewed and noted herein on a BOE basis are based on converting natural gas on the basis of relative energy content using a factor of 6,000 cubic feet of natural gas per one BOE. It should be noted that barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a BOE basis is, and has been substantially lower than the corresponding price for crude oil currently and for a number of years.

Reserves Process Review Discussion

A process review, according to Paragraph 2.2(h) contained in the Society of Petroleum Engineers (SPE) Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), is “the result of an investigation by a person who is qualified by experience and training equivalent to that of a Reserves Auditor to address the adequacy and effectiveness of an entity’s internal processes and controls relative to reserves estimation.”

In order to arrive at our conclusions and to substantiate our opinion relative to Occidental’s internal reserves estimation process and controls, we conducted our investigation in a manner that closely conforms to the SPE auditing standards for a reserves audit. Under Paragraph 2.2(f) of the SPE auditing standards, a reserves audit includes “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, and (4) the classification of reserves appropriate to the relevant definitions used.”

Our process review, however, differs from an SPE reserves audit in that we have not conducted our investigation with sufficient rigor to express an opinion as to “the reasonableness of the estimated reserve quantities and/or the Reserves Information” as required under item (5) Paragraph 2.2(f) of the SPE auditing standards for a reserves audit. Our review should not be construed to be a complete and comprehensive appraisal of the subject properties or deemed to convey the same level of information contained in a third party reserves audit or reserves evaluation report.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2020

Page 3

Applicable Petroleum Reserves Definitions

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

Reserves and Uncertainty

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2020

Page 4

Reserves Process Review Procedure

Certain technical personnel responsible for the preparation of Occidental’s proved reserves estimates presented the data, methods and procedures used in 1) estimating the reserves volumes as of December 31, 2019; 2) documenting the changes in reserves from prior estimates; 3) preparing the economic evaluations associated with the estimated December 31, 2019 reserves; and 4) determining the reserves classifications for each of the subject properties reviewed. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review. Furthermore, if in the course of our examination something came to our attention which brought into question the appropriateness of the methodologies employed, the adequacy of the data relied upon or the documentation of the reserves estimation process, additional clarification was requested from Occidental until we had satisfactorily resolved our questions relating thereto.

Methodology and Procedure Employed by Occidental for Estimating Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

The proved reserves for the properties that we reviewed were estimated by performance methods, analogy or a combination of methods. Approximately 35 percent of the proved developed producing reserves (attributable to producing wells or reservoirs) for the properties reviewed were estimated by performance methods using decline curve analysis, which utilized extrapolations of historical production and pressure data in those cases where such data were considered to be definitive. The remaining 65 percent of the proved developed producing reserves (attributable to the producing wells or reservoirs) for the properties reviewed were estimated by type curves supported by analogs to 1) estimate those reserves where there were inadequate historical performance data to establish a definitive producing trend and 2) estimate the incremental reserves attributable to enhanced/improved oil recovery. The data used by Occidental in their analysis of the proved reserves for the producing properties reviewed by us were considered sufficient for the purpose thereof.

Approximately 22 percent of the proved developed non-producing reserves were estimated by performance methods using analogy to prior established decline trends.     The remaining 78 percent of the proved developed non-producing reserves were estimated by type curves and dimensionless type curves supported by analogs. Approximately 95 percent of the proved undeveloped reserves were estimated by type curves supported by analogs. The remaining 5 percent of the proved undeveloped reserves were estimated by volumetrics and reservoir modeling. The data used by Occidental in their analysis of the non-producing and undeveloped reserves for the properties reviewed by us was considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2020

Page 5

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

Primary Economic Assumptions Employed by Occidental for Estimating Reserves

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

The hydrocarbon prices in effect on December 31, 2019 for the properties reviewed were determined by Occidental using the unweighted 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold and adjustments for differentials as described herein. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.

The table below summarizes Occidental’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Occidental’s “average realized prices.” The average realized prices shown in the table below were determined from Occidental’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Occidental’s estimate of the total net reserves for the properties reviewed by us for the geographic area. A summary of average realized prices is not included for properties located in the Middle East because of host government’s limitations on the disclosure of commercially sensitive information. The data shown in the table below is presented in accordance with SEC disclosure requirements for the North America geographic area reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$55.69/Bbl	$54.27/Bbl
United States	NGLs	WTI Cushing	$55.69/Bbl	$12.79/Bbl
	Gas	Henry Hub	$2.58/MMBTU	$1.37/MCF

As indicated above, the product prices that were used by Occidental to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and distance from market, referred to herein as

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2020

Page 6

“differentials.” The differentials used by Occidental were accepted as factual data. We have not conducted an independent verification of the data used by Occidental.

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration by Occidental in this process and omitted by us in conducting this review.

Accumulated gas production imbalances, if any, were not taken into account in the proved reserves estimates of gas reviewed. The proved gas volumes estimated by Occidental attribute gas consumed in operations as reserves for those fields where the inclusion of such volumes was appropriate.

Operating costs used by Occidental are based on the operating expense reports of Occidental and include only those costs directly applicable to the leases, contract areas and wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases, contract areas and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the Council of Petroleum Accounting Societies overhead costs that are allocated directly to the leases, contract areas and wells under terms of operating agreements. The operating costs used by Occidental were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Occidental.

Development costs used by Occidental are based on authorizations for expenditure (AFE) for the proposed work or actual costs for similar projects. The development costs used by Occidental were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Occidental.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us were incorporated by Occidental in accordance with Occidental’s plans to develop these reserves as of December 31, 2019. The implementation of Occidental’s development plans as presented to us is subject to the approval process adopted by Occidental’s management. As a result of our inquiries during the course of our review, Occidental has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Occidental’s management at the appropriate local, regional and corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to partner AFE processes, Joint Operating Agreement requirements or other administrative approvals external to Occidental. Additionally, Occidental has informed us that they are not aware of any existing laws or regulations that would require the company to significantly alter their current development plans. While these plans could change from those under existing economic conditions as of December 31, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Future Production Rate Assumptions Employed by Occidental for Estimating Reserves

Occidental’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2020

Page 7

Test data and other related information were used by Occidental to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date determined by Occidental. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Occidental’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing or recompleting wells and constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated by Occidental because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity or other operating conditions, market demand and allowables or other constraints set by regulatory bodies.

Reserves Derived by Occidental Through Certain Production Sharing Contracts

The reserves for certain properties located in the Middle East reviewed herein are limited to the period prior to expiration of current contracts providing the legal right to produce or an economic interest in such production. Furthermore, properties in different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Occidental for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Occidental’s net hydrocarbon volumes for the fields reviewed in the Middle East include certain amounts corresponding to in-country income taxes where the terms of the production sharing contract include provisions for an in-kind settlement process, where production is immediately taken and sold to pay the local income tax for and on behalf of the contractor (in this case Occidental). Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Occidental’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Possible Effects of Regulation on Occidental’s Estimate of Reserves

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Occidental operates or has interests. Occidental’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the quantities estimated by Occidental as reviewed herein.

We have not made any field examination of the properties. No consideration was given in this review to potential environmental liabilities that may exist nor to any costs for the potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Occidental has informed us that they are not aware of any existing laws or regulations that would materially impact their ability to recover the estimated proved reserves for the properties reviewed by us.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2020

Page 8

Data Reviewed in Conducting the Third Party Reserves Process Review

Occidental has informed us that they have furnished or otherwise made available to us all of the material accounts, records, geological and engineering data, and reports and other data required for this review. In conducting our process review of Occidental’s estimates of proved reserves and forecasts of future production and income, we have reviewed data used by Occidental with respect to property interests owned or otherwise held, production and well tests from examined wells, normal direct costs of operating the wells, leases and contract areas, other costs such as transportation and processing fees, ad valorem and production taxes, recompletion and development costs, development plans, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data utilized by Occidental. We consider the factual data utilized by Occidental to be appropriate and sufficient for the purpose of our review of the methods and analytical procedures utilized by the engineering and geological staff of Occidental for estimating the proved reserves volumes and preparing the economic evaluations.

Reserves Process Review Opinion

We found no bias in the utilization and analysis of data in proved reserves estimates for these properties. Furthermore, we found the estimation process incorporated all pertinent data, utilized a thorough and detailed analytical approach and was supported by a well documented audit trail.

We consider the assumptions, data, methods and analytical procedures used by Occidental and as reviewed by us appropriate for the purpose thereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties comply with the SEC regulations as of December 31, 2019. Ryder Scott has not been engaged to render an opinion as to the reasonableness of the proved reserves quantities reported by Occidental.

Standards of Independence and Professional Qualification

Ryder Scott is an employee-owned independent petroleum engineering consulting firm. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. No single client or job represents a material portion of our annual revenue. These factors allow us to maintain our independence and objectivity in the performance of our services.

Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2020

Page 9

We are independent petroleum engineers with respect to Occidental. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on the results of our review.

The results of the reserves process review, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party reserves process review, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and are intended for public disclosure as an exhibit in filings made with the SEC by Occidental.

Occidental makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Occidental has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Occidental of the references to our name as well as to the references to our third party report for Occidental, which appear in the December 31, 2019 annual report on Form 10-K of Occidental, the inclusion in that Form 10-K of such references and the filing of such report as an exhibit to such Form 10-K. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Occidental.

We have provided Occidental with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Occidental and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Guale Ramirez

Guale Ramirez, P.E.

TBPE License No. 48318

President

[SEAL]

GR/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Guale Ramirez was the primary technical person responsible for overseeing the process review and the conclusions presented herein.

Mr. Ramirez, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is the President and also serves as a member of the Board of Directors. He is responsible for executive management and supervising staff and client relations of the company. Before joining Ryder Scott, Mr. Ramirez served in a number of engineering positions with Sun Oil Company and Natomas North America. For more information regarding Mr. Ramirez’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Ramirez earned a Bachelor of Science Degree in Mechanical Engineering with honors from Texas A&M University in 1976 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ramirez fulfills. As part of his 2019 continuing education hours, Mr. Ramirez attended and internally received 12 hours of formalized training as well as a day-long public forum, the 2019 RSC Reserves Conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Ramirez has also presented courses on the SEC and SPE-PRMS reserves definitions on various occasions during 2011, 2012, 2013, 2015, 2017 and 2018, and received 20.0 hours of formalized external training during 2019, covering such topics as re-vitalization of mature fields, evaluating performance of unconventional wells, petroleum accounting, data sciences and ethics for consultants.

Based on his educational background, professional training and more than 37 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ramirez has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

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

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

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

RESERVES (SEC DEFINITIONS)

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

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

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

PROVED RESERVES (SEC DEFINITIONS)

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

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

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

DEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

Developed Producing (SPE-PRMS Definitions)

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

Developed Producing Reserves

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUMRESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

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

Developed Non-Producing

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

Shut-In

Shut-in Reserves are expected to be recovered from:

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

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

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

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

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

UNDEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.2

EXHIBIT 99.2

February 27, 2020

Occidental Petroleum Corporation

5 Greenway Plaza, Suite110

Houston, TX 77046

Re:Procedures and Methods Review of Certain of Occidental Petroleum Corporation’s Proved Reserves and Future Net Cash Flows As of December 31, 2019

Ladies and Gentlemen:

At your request, Miller and Lents, Ltd. (M&L) reviewed the procedures and methods employed by Occidental Petroleum Corporation and its subsidiaries (Occidental) in preparing its internal estimates of certain of its proved reserves and future net cash flows as of December 31, 2019. The purpose of the review was to determine whether the procedures and methods used by Occidental to estimate its proved reserves covered by this report are effective and in accordance with the definitions contained in the Securities and Exchange Commission (SEC) Regulation S-X, Rule 210.4-10(a). The results of our third party reserves review process, completed on February 12, 2020 and presented herein, were prepared for public disclosure by Occidental in filings made with the SEC in accordance with the disclosure requirements set forth under Item1202(a)(8) of Regulation S-K. The effective date of this letter is February 27, 2020.

From July through September 2019, M&L participated in the review of nine fields which included major assets in the United States and Africa. The properties reviewed by M&L account for a portion of Occidental’s total net proved reserves as of December 31, 2019. Reserves estimates for the properties reviewed herein were approximately 1,131 million barrels of oil equivalent, or approximately 30 percent of Occidental’s total proved reserves as of December 31, 2019 (in each case, excluding the Africa assets), based on information provided by Occidental. In each review, Occidental’s technical staff presented us with an overview of the data, methods, and assumptions used in its reserves estimates. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures, and relevant economic criteria.

Occidental’s proved reserves for the properties reviewed herein were estimated generally by extrapolation of well-established historical production performance trends and/or were supported by other geologic and engineering studies. Where sufficient performance data did not exist, Occidental’s reserves for these properties were estimated by volumetric calculations or by analogy to similar producing properties. M&L considers the assumptions, data, methods and analytical procedures used by Occidental and as reviewed by us appropriate for the purpose thereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Occidental Petroleum Corporation

February 27, 2020

The ownership, reversions, test and production data, operating costs, estimated capital expenditures, and other information presented by Occidental during the reviews were accepted as represented. M&L did not conduct any field inspections or other tests in conjunction with this procedures and methods review.

M&L’s work was a limited review of Occidental’s procedures and methods with respect to the properties subject to this report and does not constitute a complete review, audit, independent estimate, or confirmation of the reasonableness of Occidental’s proved reserves and future net cash flows. Occidental’s estimates of proved reserves and future net cash flows as of December 31, 2019 were determined solely by its staff and are the responsibility of its management.

Based upon M&L’s reviews and subsequent due diligence, it is our judgment that the procedures and methods employed by Occidental in estimating its December 31, 2019 proved reserves and future net cash flows for the properties subject to this report are effective and in accordance with the SEC reserves definitions.

The opinions presented in this letter reflect M&L’s informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Moreover, estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.

Miller and Lents, Ltd. is an international oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any direct financial ownership in Occidental or any affiliate company. M&L’s compensation for the required investigations is not contingent on the results obtained and reported, and M&L has not performed other work that would affect our objectivity. The procedures and methods reviews were supervised by Robert J. Oberst, an officer of the firm who is a licensed Professional Engineer in the State of Texas and professionally qualified with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Any distribution or publication of this letter or any part thereof must include this letter in its entirety.

Very truly yours,

Texas Registered Engineering Firm No. F-1442

By	/s/ Robert J. Oberst
	Robert J. Oberst, P.E.
	Chairman

2

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DERIVATIVES - ADDITIONAL INFORMATION (Details) - USD ($)		1 Months Ended	5 Months Ended	12 Months Ended
		Aug. 31, 2019	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 27, 2020	Jan. 31, 2020	Oct. 31, 2019	Aug. 08, 2019
Derivative [Line Items]
Unrealized gains (losses) on derivatives	[1]			$ (129,000,000)	$ (6,000,000)	$ 13,000,000
Not designated as hedging instruments
Derivative [Line Items]
Aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed (net of collateral)			$ 787,000,000	787,000,000	68,000,000
Amount of collateral posted related to derivative instruments with credit-risk-related contingent features			169,000,000	169,000,000	$ 1,000,000
Anadarko Petroleum Corporation
Derivative [Line Items]
Debt instrument issued										$ 21,800,000,000
Anadarko Petroleum Corporation | Senior notes
Derivative [Line Items]
Debt instrument issued										$ 13,000,000,000.0
Anadarko Petroleum Corporation | Common Stock
Derivative [Line Items]
Exercise price of warrant (usd per share)										$ 62.50
Interest Rate Swap, 6.835%
Derivative [Line Items]
Notional Principal Amount			125,000,000	125,000,000					$ 125,000,000
Interest Rate Swap, 6.835% | Subsequent Event
Derivative [Line Items]
Notional Principal Amount							$ 150,000,000
Interest Rate Swap, 6.570%
Derivative [Line Items]
Notional Principal Amount			250,000,000	$ 250,000,000
Interest Rate Swap, 6.570% | Subsequent Event
Derivative [Line Items]
Notional Principal Amount								$ 500,000,000
Warrant
Derivative [Line Items]
Initial fair value of warrant										$ 188,000,000
Interest Rate Contract
Derivative [Line Items]
Net cash receipts related to settlements			$ 120,000,000
Unrealized gains (losses) on derivatives		$ (125,000,000)
Interest Rate Contract | Senior notes
Derivative [Line Items]
Debt instrument issued		$ 13,000,000,000.0

[1] Net of tax of $36, $2 and $(7) in 2019, 2018 and 2017, respectively.

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LONG-TERM DEBT - NARRATIVE (Details) - USD ($)		1 Months Ended	4 Months Ended	12 Months Ended
	Aug. 08, 2019	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2019	Aug. 07, 2019	Jun. 04, 2019	Jun. 03, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Variable-rate debt as a percentage of total debt			12.00%	12.00%				1.00%
Anadarko Petroleum Corporation
Debt Instrument [Line Items]
Debt instrument issued	$ 21,800,000,000
Long-term debt	11,900,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, maximum borrowing capacity					$ 3,000,000,000.0
Dolphin Energy Limited
Debt Instrument [Line Items]
Limited recourse guarantees			$ 242,000,000	$ 242,000,000				$ 244,000,000
Level 1 | Fair Value
Debt Instrument [Line Items]
Estimated fair value of debt			38,800,000,000	38,800,000,000				$ 10,300,000,000
Senior notes | Anadarko Petroleum Corporation
Debt Instrument [Line Items]
Debt instrument issued	13,000,000,000.0
Long-term debt	11,900,000,000
Amount tendered and accepted in exchange offers, percentage		97.00%
Amount tendered and accepted in exchange offers,		$ 11,500,000,000
Portion not exchanged		$ 400,000,000
Senior notes | Zero Coupon senior notes due 2036
Debt Instrument [Line Items]
Debt instrument issued			$ 2,300,000,000	$ 2,300,000,000
Debt instrument interest rate stated percentage			5.24%	5.24%
Put in whole, amount			$ 992,000,000	$ 992,000,000
Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, maximum borrowing capacity						$ 5,000,000,000.0	$ 3,000,000,000.0
Average annual facility fees				0.11%
Line of Credit | Senior Unsecured Term Loan Facility, 364-Day | Anadarko Petroleum Corporation
Debt Instrument [Line Items]
Debt instrument issued	$ 4,400,000,000
Debt instrument, term	364 days
Line of Credit | Term Loan Facility | Anadarko Petroleum Corporation
Debt Instrument [Line Items]
Debt instrument issued	$ 4,400,000,000
Debt instrument, term	2 years
Secured Debt
Debt Instrument [Line Items]
Repayments of term loans			$ 7,000,000,000.0
Secured Debt | Anadarko Petroleum Corporation
Debt Instrument [Line Items]
Debt instrument issued	$ 8,800,000,000

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LEASE COMMITMENTS - LEASE ASSETS AND LIABILITIES (Details) $ in Millions	Dec. 31, 2019 USD ($)
Assets:
Operating lease assets	$ 1,385
Finance lease assets	397
Total lease assets	1,782
Assets and Liabilities, Lessee [Abstract]
Current operating lease liabilities	569
Current finance lease liabilities	51
Non-current operating lease liabilities	854
Non-current finance lease liabilities	347
Total lease liabilities	$ 1,821

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LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES - LEGAL MATTERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 30, 2019
Long-term Purchase Commitment [Line Items]
Stock accumulated					$ 1,600
Potential income tax expense	$ 925
Federal
Long-term Purchase Commitment [Line Items]
Potential income tax expense	898
State
Long-term Purchase Commitment [Line Items]
Potential income tax expense	27
Anadarko Petroleum Corporation
Long-term Purchase Commitment [Line Items]
Tax refund	881		$ 881
Accrued interest on potential income tax expense	$ 189
Arbitration Demand Filed By Andes Petroleum Ecuador Ltd
Long-term Purchase Commitment [Line Items]
Proceeds from settlement			$ 1,000
Recovery of amount awarded in settlement amount (as a percent)			60.00%
Claim to a settlement amount (as a percent)		40.00%
Own economic interest (as a percent)		60.00%
Tronox Settlement
Long-term Purchase Commitment [Line Items]
Payments for settlement				$ 5,200

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THE ACQUISITION - SCHEDULE OF PURCHASE CONSIDERATION PAID (Details) - Anadarko Petroleum Corporation $ / shares in Units, $ in Millions	Aug. 08, 2019 USD ($) $ / shares shares
Business Acquisition [Line Items]
Total shares of Anadarko common stock eligible for Merger consideration (in shares) | shares	491,600,000
Cash consideration (per share of common stock and shares underlying Anadarko stock-based awards eligible for Merger consideration) (usd per share) | $ / shares	$ 59.00
Cash portion of Acquisition consideration | $	$ 29,002
Total shares of Anadarko common stock and shares underlying Anadarko stock-based awards eligible for Merger consideration (in shares) | shares	491,600,000
Exchange ratio (per share of Anadarko common stock) | shares	0.2934
Average share price of Occidental common stock at August 8, 2019 (usd per share) | $ / shares	$ 46.31
Stock portion of Acquisition consideration | $	$ 23
Total Acquisition consideration | $	$ 35,704
Common Stock
Business Acquisition [Line Items]
Total shares of Occidental common stock issued to Anadarko stockholders (in shares) | shares	144,000,000
Average share price of Occidental common stock at August 8, 2019 (usd per share) | $ / shares	$ 46.31
Stock portion of Acquisition consideration | $	$ 6,679

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - DERIVATIVE INSTRUMENTS (Details)	12 Months Ended
	Dec. 31, 2019
Low end of range
DERIVATIVE INSTRUMENTS
Range used to determine if derivative instrument is effective	80.00%
High end of range
DERIVATIVE INSTRUMENTS
Range used to determine if derivative instrument is effective	125.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ASSET IMPAIRMENTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Summary of significant accounting policies
Impairments of assets	$ 285
Qatar ISSD
Summary of significant accounting policies
Impairments of assets	$ 39
Qatar ISND and ISSD
Summary of significant accounting policies
Impairments of assets		$ 416
Proved and unproved non-core Permian
Summary of significant accounting policies
Impairments of assets			$ 397
Marketing and Midstream
Summary of significant accounting policies
Impairments of assets		$ 100
Other asset impairment related charges			$ 120

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of cash equivalents and restricted cash equivalents

The following table provides a reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents as reported at the end of the period in the Consolidated Statements of Cash Flows for the twelve months ended December 31, 2019 to the line items within the Consolidated Balance Sheet at December 31, 2019. There was no restricted cash or restricted cash equivalents at December 31, 2018.

millions	December 31, 2019
Cash and cash equivalents	$	3,032
Restricted cash and restricted cash equivalents	480
Cash and restricted cash included in assets held for sale	8
Restricted cash and restricted cash equivalents included in long-term receivables and other assets, net	54
Cash, cash equivalents, restricted cash, and restricted cash equivalents	$	3,574

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

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

millions	2019			2018			2017
Balance — beginning of year	$	112		$	108		$	56
Exploratory well costs acquired through the Acquisition	231			—			—
Additions to capitalized exploratory well costs pending the determination of proved reserves	383			220			201
Reclassifications to property, plant and equipment based on the determination of proved reserves	(230		)	(198		)	(128		)
Capitalized exploratory well costs charged to expense	(72		)	(18		)	(21		)
Balance — end of year	$	424		$	112		$	108

Summary of the activity of the asset retirement obligation

The following table summarizes the activity of asset retirement obligations for the years ended December 31,:

millions	2019			2018
Beginning balance	$	1,499		$	1,312
Liabilities assumed in the Acquisition	3,344			—
Liabilities incurred – capitalized to PP&E	131			31
Liabilities settled and paid	(200		)	(40		)
Accretion expense	71			67
Acquisitions, dispositions and other	—			(18		)
WES loss of control	(359		)	—
Revisions to previous estimates	147			147
Ending balance (a)	$	4,633		$	1,499

^(a)  The ending balance included $248 million and $75 million related to the current balance of AROs that are included in Accrued Liabilities on the Consolidated Balance Sheets at December 31, 2019 and 2018, respectively.

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INVENTORIES (Tables)

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

Schedule of inventories

Inventories consisted of the following at December 31:

millions	2019			2018
Raw materials	$	75		$	74
Materials and supplies	879			445
Commodity inventory and finished goods	533			788
	1,487			1,307
Revaluation to LIFO	(40		)	(47		)
Total	$	1,447		$	1,260

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Method Investments
Equity method investment amounts	$ 6,389	$ 1,680	$ 1,515
Equity investments dividends paid	422	329	297
Excess of investments in equity investees over the underlying equity in net assets	3,600
Excess of investments in equity investees over the underlying equity in net assets, which represents goodwill	1,500
Equity-method investments financial information summarized by Income Statement line item
Revenues and other income	26,520	28,091	13,843
Costs and expenses	24,084	25,029	12,230
Net income	2,436	3,062	1,613
Equity-method investments financial information summarized by Balance Sheet line item
Current assets	1,130	5,587	5,754
Non-current assets	21,158	25,871	25,108
Current liabilities	785	4,879	4,479
Long-term debt	8,673	12,505	14,091
Other non-current liabilities	859	95	414
Stockholders’ equity	11,971	13,979	11,878
RELATED-PARTY TRANSACTIONS
Sales	691	805	636
Purchases	463	502	387
Services	28	52	38
Advances and amounts due from related parties	133	63	63
Amounts due to related parties	$ 463	$ 46	$ 45
Note payable | WES
RELATED-PARTY TRANSACTIONS
Debt instrument interest rate stated percentage	6.50%
Anadarko Petroleum Corporation
Equity Method Investments
Equity method investment amounts	$ 2,800
Note payable	2,800
WES
Equity Method Investments
Equity method investment amounts	$ 5,128
Equity method investment ownership percentage	56.30%
OxyChem Ingleside Facility
Equity Method Investments
Equity method investment amounts	$ 679
Equity method investment ownership percentage	50.00%
Dolphin Energy Limited
Equity Method Investments
Equity method investment amounts	$ 240
Equity method investment ownership percentage	24.50%
Other
Equity Method Investments
Equity method investment amounts	$ 342
General Partner of Plains All American Pipeline, L.P
Equity Method Investments
Ownership interest (as a percent)		11.00%
RELATED-PARTY TRANSACTIONS
Sales to related party (as a percent)	87.00%	89.00%	86.00%
Plains All American Pipeline, LP
Equity Method Investments
Ownership interest (as a percent)		40.00%
Ingleside Ethylene LLC
RELATED-PARTY TRANSACTIONS
Purchases from related party (as a percent)	98.00%	98.00%

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ENVIRONMENTAL LIABILITIES AND EXPENDITURES (Tables)

12 Months Ended

Dec. 31, 2019

Environmental Remediation Obligations [Abstract]

Schedule of current and non-current environmental remediation reserves by categories of sites

	2019			2018
millions, except number of sites	Number of Sites	Remediation Balance		Number of Sites	Remediation Balance
NPL sites	36	$	463	34	$	458
Third-party sites	74	311		68	168
Occidental-operated sites	17	154		14	115
Closed or non-operated Occidental sites	50	269		29	141
Total	177	$	1,197	145	$	882

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Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Allowance for doubtful accounts
Valuation and qualifying accounts
Balance at Beginning of Period	$ 668	$ 594	$ 558
Charged to Costs and Expenses	126	77	37
Charged to Other Accounts	(6)	(3)	(2)
Deductions	0	0	1
Balance at End of Period	788	668	594
Valuation allowance and reserves, current	22	24	18
Environmental, litigation and other reserves
Valuation and qualifying accounts
Balance at Beginning of Period	994	935	997
Charged to Costs and Expenses	182	140	45
Charged to Other Accounts	1,408	85	53
Deductions	(173)	(166)	(160)
Balance at End of Period	2,411	994	935
Valuation allowance and reserves, current	$ 188	$ 146	$ 163

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LEASE COMMITMENTS

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

LEASE COMMITMENTS

NOTE 8 - LEASE COMMITMENTS

On January 1, 2019, Occidental adopted ASC 842 using the modified retrospective approach, which provided a method for recording existing leases at adoption and did not require restatement of prior year amounts and disclosures, which continue to be reflected in accordance with ASC 840. Occidental elected certain practical expedients as follows:

Ø Leases that commenced before the effective date carried forward their historical lease classification.

Ø Existing or expired land easements as of December 31, 2018, were not reassessed to determine whether or not they contained a lease.

Ø Leases with a lease term of 12 months or less from lease commencement date are considered short-term leases and not recorded on the Consolidated Balance Sheet; however, the lease expenditures recognized are captured and reported as incurred.

Ø For asset classes, except long-term drilling rigs, Occidental elected to account for the lease and non-lease components as a single lease component as the non-lease portions were not significant to separate in determining the lease liability. For long-term drilling rig contracts, Occidental bifurcated the lease and non-lease components using relative fair value as a stand-alone selling price between the asset rental and the services obtained.

ASC 842 requires lessees to recognize a ROU asset and lease liability for all long-term leases. A ROU asset represents Occidental’s right to use an underlying asset for the lease term and the associated lease liability represents the discounted obligation of future minimum lease payments. Occidental identifies leases through its accounts payable and contract monitoring process. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. The ROU assets include the discounted obligation in addition to any upfront payments or costs incurred during the contract execution of the lease and amortized on a straight-line basis over the course of the lease term. Except for leases with explicitly defined contract terms, Occidental utilizes judgment to assess likelihood of renewals, terminations and purchase options, in order to determine the lease term. Occidental uses the incremental borrowing rate at commencement date to determine the present value of lease payments. The incremental borrowing rate equates to the rate of interest that Occidental would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. Certain leases include variable lease payments which are over and above the minimum lease liability used to derive the ROU asset and lease liability and are based on the underlying asset’s operations. These variable lease costs are reported in the lease cost classification table.

Recognition, measurement, and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. The criteria for distinguishing between finance and operating leases are substantially similar to the criteria under ASC 840. For Occidental operations, adoption of ASC 842 resulted in recording of net lease assets and lease liabilities of $772 million as of January 1, 2019. There was no material impact to net income, cash flows, or stockholders’ equity.

ACQUISITION IMPACT

ASC 805 Business Combinations requires lease-related assets and liabilities acquired to be measured as if the lease were new at the acquisition date. Occidental measured the Anadarko lease agreements using Occidental’s incremental borrowing rates. This resulted in Anadarko assets and lease liabilities of $503 million and $574 million, respectively, excluding the Africa Assets at the Acquisition date, being evaluated and adjusted, as necessary, for above- or below -market impacts. For the leases acquired through the Acquisition, Occidental will retain the previous lease classification.

The following table reconciles the undiscounted cash flows related to the operating and finance lease liabilities assumed in the Acquisition and recorded on the Consolidated Balance Sheet at the Acquisition date:

millions	Operating Leases			Finance Leases			Total
2019	$	90		$	7		$	97
2020	172			17			189
2021	64			16			80
2022	42			13			55
2023	28			8			36
Thereafter	136			43			179
Total lease payments	$	532		$	104		$	636
Less: Interest	(44		)	(18		)	(62		)
Total lease liabilities (a)	$	488		$	86		$	574

^(a)  Excluded operating and finance leases associated with the Africa Assets of $74 million and $201 million, respectively.

Additionally, Occidental has elected short-term lease treatment for those acquired lease contracts which, at the Acquisition date, had a remaining lease term of 12 months or less.

NATURE OF LEASES

Occidental’s operating lease agreements include leases for oil and gas exploration and development equipment, including offshore and onshore drilling rigs of $217 million, compressors of $162 million and other field equipment of $389 million, which are recorded gross on the Consolidated Balance Sheet and in the lease cost disclosures below. Contract expiration terms generally range from 2 to 9 years. Further, actual expenditures are netted against joint-interest recoveries on the statement of operations through the normal joint-interest billing process. Occidental’s leases also include pipelines, rail cars, storage facilities, easements and real estate of $659 million, which typically are not associated with joint-interest recoveries. Real estate leases have contract expiration terms ranging from 1 to 14 years.

Occidental’s finance lease agreements include leases for oil and gas exploration and development equipment, as well as real estate offices, compressors, and field equipment of approximately $398 million.

The following table presents lease balances and their location on the Consolidated Balance Sheet at December 31, 2019:

millions	Balance sheet location	2019
Assets:
Operating	Operating lease assets	$	1,385
Finance	Property, plant and equipment	397
Total lease assets		$	1,782
Liabilities:
Current
Operating	Current operating lease liabilities	$	569
Finance	Current maturities of long-term debt	51
Non-current
Operating	Deferred credits and other liabilities - Operating lease liabilities	854
Finance	Long-term debt, net	347
Total lease liabilities		$	1,821

At December 31, 2019, Occidental’s leases expire based on the following schedule:

millions	Operating Leases(a)			Finance Leases(b)			Total
2020	$	555		$	53		$	608
2021	408			45			453
2022	136			41			177
2023	99			37			136
2024	81			34			115
Thereafter	254			275			529
Total lease payments	1,533			485			2,018
Less: Interest	(110		)	(87		)	(197		)
Total lease liabilities	$	1,423		$	398		$	1,821

^(a)  The weighted-average remaining lease term is 4.6 years and the weighted-average discount rate is 2.53%.

^(b)  The weighted-average remaining lease term is 11.6 years and the weighted-average discount rate is 3.74%.

At December 31, 2018, future undiscounted net minimum fixed lease payments for non-cancellable operating leases, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows:

millions	Operating Leases
2019	$	186
2020	147
2021	96
2022	68
2023	49
Thereafter	158
Total minimum lease payments(a)	$	704

^(a)  The amount represents the future undiscounted cash flows at December 31, 2018, excluding any amount associated with the Acquisition.

The following tables present Occidental’s total lease cost and classifications, as well as cash paid for amounts included in the measurement of operating and finance lease liabilities:

millions	Year ended December 31, 2019
Lease cost classification(a)
Operating lease costs(b)
Property, plant and equipment, net		$	449
Operating expense and cost of sales		391
Selling, general and administrative expenses		92
Finance lease cost
Amortization of ROU assets		19
Interest on lease liabilities		2
Total lease cost		$	953

^(a)  Amounts reflected are gross before joint-interest recoveries.

^(b)  Included short-term lease cost of $404 million for the twelve months ended December 31, 2019, and variable lease cost of $162 million for the twelve months ended December 31, 2019.

millions	Year ended December 31, 2019
Operating cash flows		$	262
Investing cash flows		$	112
Financing cash flows (a)		$	19

^(a) 

Excludes cash received of approximately $300 million associated with the failed sale-leaseback, see Note 4 - Acquisitions, Dispositions and Other.

LEASE COMMITMENTS

NOTE 8 - LEASE COMMITMENTS

On January 1, 2019, Occidental adopted ASC 842 using the modified retrospective approach, which provided a method for recording existing leases at adoption and did not require restatement of prior year amounts and disclosures, which continue to be reflected in accordance with ASC 840. Occidental elected certain practical expedients as follows:

Ø Leases that commenced before the effective date carried forward their historical lease classification.

Ø Existing or expired land easements as of December 31, 2018, were not reassessed to determine whether or not they contained a lease.

Ø Leases with a lease term of 12 months or less from lease commencement date are considered short-term leases and not recorded on the Consolidated Balance Sheet; however, the lease expenditures recognized are captured and reported as incurred.

Ø For asset classes, except long-term drilling rigs, Occidental elected to account for the lease and non-lease components as a single lease component as the non-lease portions were not significant to separate in determining the lease liability. For long-term drilling rig contracts, Occidental bifurcated the lease and non-lease components using relative fair value as a stand-alone selling price between the asset rental and the services obtained.

ASC 842 requires lessees to recognize a ROU asset and lease liability for all long-term leases. A ROU asset represents Occidental’s right to use an underlying asset for the lease term and the associated lease liability represents the discounted obligation of future minimum lease payments. Occidental identifies leases through its accounts payable and contract monitoring process. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. The ROU assets include the discounted obligation in addition to any upfront payments or costs incurred during the contract execution of the lease and amortized on a straight-line basis over the course of the lease term. Except for leases with explicitly defined contract terms, Occidental utilizes judgment to assess likelihood of renewals, terminations and purchase options, in order to determine the lease term. Occidental uses the incremental borrowing rate at commencement date to determine the present value of lease payments. The incremental borrowing rate equates to the rate of interest that Occidental would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. Certain leases include variable lease payments which are over and above the minimum lease liability used to derive the ROU asset and lease liability and are based on the underlying asset’s operations. These variable lease costs are reported in the lease cost classification table.

Recognition, measurement, and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. The criteria for distinguishing between finance and operating leases are substantially similar to the criteria under ASC 840. For Occidental operations, adoption of ASC 842 resulted in recording of net lease assets and lease liabilities of $772 million as of January 1, 2019. There was no material impact to net income, cash flows, or stockholders’ equity.

ACQUISITION IMPACT

ASC 805 Business Combinations requires lease-related assets and liabilities acquired to be measured as if the lease were new at the acquisition date. Occidental measured the Anadarko lease agreements using Occidental’s incremental borrowing rates. This resulted in Anadarko assets and lease liabilities of $503 million and $574 million, respectively, excluding the Africa Assets at the Acquisition date, being evaluated and adjusted, as necessary, for above- or below -market impacts. For the leases acquired through the Acquisition, Occidental will retain the previous lease classification.

The following table reconciles the undiscounted cash flows related to the operating and finance lease liabilities assumed in the Acquisition and recorded on the Consolidated Balance Sheet at the Acquisition date:

millions	Operating Leases			Finance Leases			Total
2019	$	90		$	7		$	97
2020	172			17			189
2021	64			16			80
2022	42			13			55
2023	28			8			36
Thereafter	136			43			179
Total lease payments	$	532		$	104		$	636
Less: Interest	(44		)	(18		)	(62		)
Total lease liabilities (a)	$	488		$	86		$	574

^(a)  Excluded operating and finance leases associated with the Africa Assets of $74 million and $201 million, respectively.

Additionally, Occidental has elected short-term lease treatment for those acquired lease contracts which, at the Acquisition date, had a remaining lease term of 12 months or less.

NATURE OF LEASES

Occidental’s operating lease agreements include leases for oil and gas exploration and development equipment, including offshore and onshore drilling rigs of $217 million, compressors of $162 million and other field equipment of $389 million, which are recorded gross on the Consolidated Balance Sheet and in the lease cost disclosures below. Contract expiration terms generally range from 2 to 9 years. Further, actual expenditures are netted against joint-interest recoveries on the statement of operations through the normal joint-interest billing process. Occidental’s leases also include pipelines, rail cars, storage facilities, easements and real estate of $659 million, which typically are not associated with joint-interest recoveries. Real estate leases have contract expiration terms ranging from 1 to 14 years.

Occidental’s finance lease agreements include leases for oil and gas exploration and development equipment, as well as real estate offices, compressors, and field equipment of approximately $398 million.

The following table presents lease balances and their location on the Consolidated Balance Sheet at December 31, 2019:

millions	Balance sheet location	2019
Assets:
Operating	Operating lease assets	$	1,385
Finance	Property, plant and equipment	397
Total lease assets		$	1,782
Liabilities:
Current
Operating	Current operating lease liabilities	$	569
Finance	Current maturities of long-term debt	51
Non-current
Operating	Deferred credits and other liabilities - Operating lease liabilities	854
Finance	Long-term debt, net	347
Total lease liabilities		$	1,821

At December 31, 2019, Occidental’s leases expire based on the following schedule:

millions	Operating Leases(a)			Finance Leases(b)			Total
2020	$	555		$	53		$	608
2021	408			45			453
2022	136			41			177
2023	99			37			136
2024	81			34			115
Thereafter	254			275			529
Total lease payments	1,533			485			2,018
Less: Interest	(110		)	(87		)	(197		)
Total lease liabilities	$	1,423		$	398		$	1,821

^(a)  The weighted-average remaining lease term is 4.6 years and the weighted-average discount rate is 2.53%.

^(b)  The weighted-average remaining lease term is 11.6 years and the weighted-average discount rate is 3.74%.

At December 31, 2018, future undiscounted net minimum fixed lease payments for non-cancellable operating leases, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows:

millions	Operating Leases
2019	$	186
2020	147
2021	96
2022	68
2023	49
Thereafter	158
Total minimum lease payments(a)	$	704

^(a)  The amount represents the future undiscounted cash flows at December 31, 2018, excluding any amount associated with the Acquisition.

The following tables present Occidental’s total lease cost and classifications, as well as cash paid for amounts included in the measurement of operating and finance lease liabilities:

millions	Year ended December 31, 2019
Lease cost classification(a)
Operating lease costs(b)
Property, plant and equipment, net		$	449
Operating expense and cost of sales		391
Selling, general and administrative expenses		92
Finance lease cost
Amortization of ROU assets		19
Interest on lease liabilities		2
Total lease cost		$	953

^(a)  Amounts reflected are gross before joint-interest recoveries.

^(b)  Included short-term lease cost of $404 million for the twelve months ended December 31, 2019, and variable lease cost of $162 million for the twelve months ended December 31, 2019.

millions	Year ended December 31, 2019
Operating cash flows		$	262
Investing cash flows		$	112
Financing cash flows (a)		$	19

^(a) 

Excludes cash received of approximately $300 million associated with the failed sale-leaseback, see Note 4 - Acquisitions, Dispositions and Other.

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

NOTE 4 - ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

AFRICA ASSETS - DISCONTINUED OPERATIONS

In September 2019, Occidental completed the sale of Mozambique LNG assets to Total for approximately $4.2 billion, with proceeds used to pay down a portion of the Term Loans. In January 2020, Occidental completed the sale of South Africa assets to Total. Occidental and Total continue to work toward completing the sales of the remaining Africa Assets. The carrying amount of the remaining Africa Assets will be adjusted in future periods based on changes in fair value. The results of the Africa Assets are presented as discontinued operations in the Consolidated Statements of Operations and Cash Flows.

The following table presents the amounts reported in discontinued operations, net of income taxes, related to the Africa Assets subsequent to the Acquisition closing date through December 31, 2019:

millions	2019
Revenues and other income
Net sales	$	739
Costs and other deductions
Oil and gas lease operating expense	$	81
Transportation expense	14
Taxes other than on income	133
Fair value adjustment on assets held for sale	244
Other	53
Total costs and other deductions	$	525
Income before income taxes	$	214
Income tax expense	(229		)
Discontinued operations, net of tax	$	(15	)

The following table presents amounts related to the Africa Assets reported as held for sale in the Consolidated Balance Sheet as of December 31, 2019:

millions	2019
Current assets	$	289
Property, plant and equipment, net	5,481
Long-term receivables and other assets, net	256
Assets held for sale (a)	$	6,026
Current liabilities	$	452
Long-term debt, net - finance leases	185
Deferred income taxes	1,112
Asset retirement obligations	181
Other	80
Liabilities of assets held for sale (a)	$	2,010
Net assets held for sale	$	4,016

^(a)  Assets and liabilities held for sale at December 31, 2019 included South Africa assets which were sold to Total in January 2020.

OTHER TRANSACTIONS

2019

In December 2019, Occidental disposed of real estate assets for $565 million. Occidental utilized net proceeds to pay down a portion of the Term Loans. Concurrent with the sale, Occidental entered a thirteen-year lease for part of the real estate assets. Based on the terms of the lease, Occidental treated this as a failed sale-leaseback, retained the related book value in property, plant and equipment and recognized a finance lease of approximately $300 million based on the discounted future minimum lease payments.

In November 2019, Occidental and Ecopetrol closed on the joint venture to develop approximately 97,000 net acres of Occidental’s Midland Basin unproved properties in the Permian Basin. Ecopetrol paid $750 million in cash at closing and up to $750 million of carried capital in exchange for a 49% interest in the new venture. Occidental recognized a gain of $563 million on the sale. Following the close, Occidental owned a 51% interest and operates the joint venture. During the carry period, Ecopetrol will pay 75% of Occidental’s share of capital expenditures, up to $750 million. The joint venture allows Occidental to accelerate its development plans in the Midland Basin, where it currently has minimal activity. Occidental will retain production and cash flow from its existing operations in the Midland Basin. The proceeds were used to pay down a portion of the Term Loans.

In September 2019, Occidental sold its remaining equity investment in Plains All American Pipeline, L.P. and Plains GP Holdings, L.P. (together, Plains) for net proceeds of $646 million, which resulted in a pre-tax gain of $114 million. The proceeds were used to pay down a portion of the Term Loans.

2018

In September 2018, Occidental divested non-core domestic midstream assets for total consideration of $2.6 billion, of which approximately $2.4 billion was received at closing, resulting in a pre-tax net gain of $907 million. These assets include the Centurion common carrier oil pipeline and storage system, Southeast New Mexico oil gathering system, and Ingleside Crude Terminal. Following the transactions, Occidental retained its long-term flow assurance, pipeline takeaway and export capacity through its retained marketing business.

In July 2018, Occidental acquired a previously leased power and steam cogeneration facility for $443 million.

In March 2018, Occidental divested non-core midstream assets for approximately $150 million, resulting in a pre-tax gain of $43 million.

2017

In the third quarter of 2017, Occidental closed on two divestitures of non-core acreage in the Permian Basin for proceeds of approximately $0.6 billion, resulting in a pre-tax gain of approximately $81 million. Concurrently, Occidental purchased additional ownership interests and assumed operatorship in CO₂ enhanced oil recovery (EOR) properties located in the Seminole-San Andres Unit for approximately $0.6 billion, which was primarily allocated to proved property. In the fourth quarter of 2017, Occidental sold other non-core proved and unproved acreage in the Permian Basin for approximately $90 million, resulting in a pre-tax gain of approximately $55 million. Occidental also classified approximately $0.5 billion in non-core proved and unproved Permian acreage to assets held for sale at December 31, 2017.

In April 2017, Occidental completed the sale of its South Texas operations for net proceeds of $0.5 billion resulting in pre-tax gain of $0.5 billion.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

PRINCIPLES OF CONSOLIDATION

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, variable interest entities (VIE) for which Occidental is the primary beneficiary, 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, statements of operations and statements of cash flows.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates for 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.

RISKS AND UNCERTAINTIES

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with GAAP requires Occidental’s management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements. Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets 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 $14.9 billion as of December 31, 2019, and net sales of approximately $4.6 billion for the year ended December 31, 2019, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that have experienced political instability, nationalizations, corruption, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions, all of which increase Occidental’s risk of loss, 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.

CASH EQUIVALENTS AND RESTRICTED CASH EQUIVALENTS

Total restricted cash and restricted cash equivalents are primarily associated with a benefits trust for former Anadarko employees, payments of future hard-minerals royalties conveyed, and a judicially-controlled account related to a Brazilian tax dispute.

CASH EQUIVALENTS AND RESTRICTED CASH EQUIVALENTS

Occidental considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents. The cash equivalents and restricted cash equivalents balance at December 31, 2019, included investments in government money market funds in which the carrying value approximates fair value.

INVENTORIES

INVENTORIES

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

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

PROPERTY, PLANT AND EQUIPMENT

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. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether Occidental is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

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 leasehold 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 performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to prolonged declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include future production and timing of production, estimates of future product prices, contractual prices, estimates of risk-adjusted oil and gas reserves and estimates of future operating and development costs. See Note 17 - Fair Value Measurements and below for further discussion of asset impairments.

The unproved amounts are not subject to DD&A until they are classified as proved properties. Individually insignificant unproved properties are combined and amortized on a group basis based on factors such as lease terms, success rates, and other factors. If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. Occidental periodically reviews unproved properties for impairments; numerous factors are considered, including but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property or the adjacent property, geologists’ evaluation of the property and the remaining lease term for the property. Management’s assessment of the availability of funds for future activities and the current and projected political and regulatory climate in areas in which Occidental operates also impacts the timing of any impairment.

CHEMICAL

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

Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are affected by domestic and international 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.

MARKETING AND MIDSTREAM

Occidental’s marketing and midstream 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 marketing and midstream 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.

GOODWILL

GOODWILL

Occidental recognized goodwill of $5.8 billion associated with the Acquisition. The goodwill was based on WES’s publicly traded units and was primarily associated with the relationship between Occidental and WES as well as Occidental’s tax basis in WES. Upon loss of control and application of the equity method of accounting, $4.6 billion of goodwill was derecognized. The remaining $1.2 billion in goodwill is assigned to the marketing and midstream segment and is attributable to the deferred tax liability associated with the investment in WES.

Goodwill is subject to annual impairment testing every October. Occidental’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is likely impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill, Occidental will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures.

IMPAIRMENTS AND OTHER CHARGES

IMPAIRMENTS AND OTHER CHARGES

During 2019, Occidental’s Oil and Gas segment recognized pre-tax impairment and related charges of $285 million related to domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and $39 million related to Occidental’s mutually agreed early termination of its Qatar Idd El Shargi South Dome (ISSD) contract.

During 2018, Occidental recognized pre-tax impairment and related charges of $416 million related to Qatar Idd El Shargi North Dome (ISND) and ISSD proved properties and inventory. The fair value of the proved properties was measured based on the income approach, which 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, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk-adjusted discount rate of 10%. These inputs are categorized as Level 3 in the fair-value hierarchy.

Also in 2018, the marketing and midstream segment incurred approximately $100 million of charges primarily for lower of cost or market adjustments on its crude inventory and line fill.

In 2017, Occidental recorded net impairment and related charges of $397 million related to proved and unproved non-core Permian acreage and $120 million related to idled marketing and midstream facilities.

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

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

FAIR VALUES - RECURRING

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

Ø Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1.

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

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

Ø Occidental values debt using market-observable information for debt instruments that are traded on secondary markets. For debt instruments that are not traded, the fair value is determined by interpolating the value based on debt with similar terms and credit risk.

NON-FINANCIAL ASSETS

Occidental uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When Occidental is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows, and the expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions.

ACCRUED LIABILITIES-CURRENT

ACCRUED LIABILITIES - CURRENT

Accrued liabilities - current included accrued payroll, commissions and related expenses of $1.2 billion and $428 million at December 31, 2019, and 2018, respectively. Dividends payable, also included in accrued liabilities - current, were $884 million and $600 million at December 31, 2019, and 2018, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental liabilities 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 environmental remediation liability 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 its environmental remediation liabilities 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 its environmental remediation liabilities and adjusts them as new information becomes available. Occidental records environmental remediation liabilities 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. Presently none of its environmental remediation liabilities 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.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental remediation liabilities and the range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may vary from the initial estimate; (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 its environmental remediation liabilities at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental’s environmental remediation liabilities 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 environmental remediation liabilities accordingly.

ASSET RETIREMENT OBLIGATIONS

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, 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 obligations changes, Occidental records an adjustment to both the asset retirement obligations 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.

The majority of Occidental’s asset retirement obligations relate to the plugging of wells and the related abandonment of oil and gas properties. Revisions in estimated liabilities during the period primarily relate to liabilities acquired in the Acquisition and include, but are not limited to, changes in estimates of asset retirement costs, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlements.

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.

DERIVATIVE INSTRUMENTS

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 carrying value 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 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 operations. There were no fair value hedges as of and during the years ended December 31, 2019, 2018 and 2017.

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% of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. Occidental discontinues hedge accounting when it determines that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

STOCK-BASED INCENTIVE PLANS

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 14 - Stock-Based Incentive Plans. 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 (RSU), cash return on capital employed incentive awards (CROCEI), return on capital employed incentive awards (ROCEI) and return on assets incentive awards (ROAI), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout at the grant date. For total shareholder return incentive awards (TSRI), compensation value is initially measured on the grant date using estimated payout levels derived from a Monte Carlo valuation model. Compensation expense for RSUs, CROCEIs, ROCEIs, ROAIs 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. Dividends accrued on unvested awards are adjusted quarterly for any changes in the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable. All such performance or stock-price-related changes are recognized in periodic compensation expense. The stock-settled portion of these awards is expensed using the initially measured compensation value. The liability resulting from the cash settled portion of these awards and accrued dividends are remeasured at each reporting period.

EARNINGS PER SHARE

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, 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

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 15 - Retirement and Postretirement Benefit Plans, in its financial statements using a December 31 measurement date.

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

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

FOREIGN CURRENCY TRANSACTIONS

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s international oil and gas operations is the U.S. dollar since cash flows are denominated principally in U.S. 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.

INCOME TAXES

INCOME TAXES

Occidental files various U.S. federal, state, and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Occidental routinely assesses the realizability of its deferred tax assets. If Occidental concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Occidental recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit).

OTHER LOSS CONTINGENCIES

OTHER LOSS CONTINGENCIES

Occidental 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. Occidental or certain of its subsidiaries also are involved in proceedings under CERCLA and similar federal, state, local and international 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 Occidental 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 outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated.

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

In January 2019, Occidental adopted the new lease standard Accounting Standards Codification Topic 842 - Leases (ASC 842). The new standard requires Occidental to recognize most leases, including operating leases, on the balance sheet. The new rules require lessees to recognize a right-of-use (ROU) asset and lease liability for all leases with lease terms of more than 12 months. Occidental adopted the standard using the modified retrospective approach, including adopting several optional practical expedients. See Note 8 - Lease Commitments.

In February 2018, the Financial Accounting Standards Board (FASB) released standards that allow the reclassification from accumulated other comprehensive income to retained earnings of stranded tax effects resulting from changes to U.S. federal tax law from the 2017 Tax Cuts and Jobs Act (Tax Reform) enacted in December 2017. Occidental early adopted this standard in the first quarter of 2018, resulting in the reclassification of $58 million in stranded tax effects from accumulated other comprehensive income (AOCI) to retained earnings.

In January 2018, Occidental adopted the new revenue recognition standard Topic 606 - Revenue from Contracts with Customers and related updates (ASC 606). The new standard requires more detailed disclosures related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Occidental adopted the standard using the modified retrospective method. The cumulative-effect adjustment to retained earnings upon adoption was not material. See Note 5 - Revenue.

In January 2017, FASB issued new guidance clarifying the definition of a business under the topic Business Combinations. The rules became effective in the first quarter of 2018, and did not have a material impact to Occidental’s financial statements upon adoption.

REVENUE RECOGNITION

Revenue from customers is recognized when obligations under the terms of a contract are satisfied; this generally occurs with the delivery of oil, gas, NGL, chemicals or services such as transportation. Revenue from customers is measured as the amount of consideration Occidental expects to receive in exchange for the delivery of goods or services. Contracts may last from one month to one year or more, and may have renewal terms that extend indefinitely at the option of either party. Price is typically based on market indexes. Volumes fluctuate due to production and, in certain cases, customer demand and transportation availability. Occidental records revenue net of certain taxes, such as sales taxes, that are assessed by governmental authorities on Occidental’s customers.

Occidental does not incur significant costs to obtain contracts. Incidental items that are immaterial in the context of the contract are recognized as expenses. Sales of hydrocarbons and chemicals to customers are invoiced and settled on a monthly basis. Occidental is not usually subject to obligations for warranties, rebates, returns or refunds except in the case of customer incentive payments as discussed for the chemical segment below. Occidental does not typically receive payment in advance of satisfying its obligations under the terms of its sales contracts with customers; therefore, liabilities related to such payment are immaterial to Occidental.

OIL AND GAS SEGMENT

Revenue from oil and gas production is recognized when production is delivered and control passes to the customer. 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.

CHEMICALS SEGMENT

Revenue from chemical product sales is recognized when control passes 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. Customer incentives are estimated and recorded as a reduction to revenue ratably over the contract period. Such estimates are evaluated and revised as warranted. Revenue from exchange contracts is excluded from revenue from customers.

MARKETING AND MIDSTREAM SEGMENT

Revenue from pipeline and gas processing is recognized upon the completion of the transportation or processing service. Revenue from power sales is recognized upon delivery. Net marketing revenue is included in net sales, but excluded from revenue from customers in the table below. Net marketing revenue is recognized upon completion of contract terms that are a prerequisite to payment and upon title transfer for physical deliveries. Unless the normal purchases and sales exception has been elected, net marketing revenue is classified as a derivative, reported on a net basis, recorded at fair value and changes in fair value are reflected in net sales.

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2019

Investments And Related Party Transactions Disclosure [Abstract]

INVESTMENTS AND RELATED-PARTY TRANSACTIONS

NOTE 16 - INVESTMENTS AND RELATED-PARTY TRANSACTIONS

EQUITY INVESTMENTS

As of December 31, 2019, and 2018, investments in unconsolidated entities were $6.4 billion and $1.7 billion, respectively. As of December 31, 2019, Occidental’s significant equity investments primarily consisted of the following:

millions	% Interest		Carrying amount
WES	56.3	%	$	5,128
OxyChem Ingleside Facility	50.0	%	679
Dolphin Energy Limited	24.5	%	240
Other	various		342
Total			$	6,389

As of December 31, 2018, Occidental’s significant equity investments consisted of investments in Plains, OxyChem Ingleside Facility and Dolphin Energy Limited. In September 2019, Occidental sold its equity investment in Plains, which consisted of an 11 percent interest in the general partner that owned approximately 40 percent in Plains Pipeline. See Note 4 - Acquisitions, Dispositions, and Other Transactions for additional information.

As part of the Acquisition, Occidental acquired equity investments in certain oil and gas properties and gathering and processing assets and assumed an associated notes payable which Occidental has the legal right of setoff and intends to net settle with its ownership interest in the equity investments. The notes payable can be net settled starting in 2022. The carrying value of the investment and note payable was $2.8 billion and $2.8 billion at December 31, 2019, respectively. Accordingly, the equity investments and the related notes payable are presented net on the Consolidated Balance Sheets. 

Dividends received from equity investments were $422 million, $329 million, and $297 million to Occidental in 2019, 2018 and 2017, respectively. As of December 31, 2019, cumulative undistributed earnings of equity-method investees since they were acquired was immaterial. As of December 31, 2019, Occidental’s investments in equity investees exceeded the underlying equity in net assets by approximately $3.6 billion, of which $1.5 billion represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

The following table presents the summarized financial information of its equity-method investments combined for the years ended and as of December 31:

millions	2019		2018		2017
Summarized Results of Operations(a)
Revenues and other income	$	26,520	$	28,091	$	13,843
Costs and expenses	24,084		25,029		12,230
Net income	$	2,436	$	3,062	$	1,613
Summarized Balance Sheet(b)
Current assets	$	1,130	$	5,587	$	5,754
Non-current assets	$	21,158	$	25,871	$	25,108
Current liabilities	$	785	$	4,879	$	4,479
Long-term debt	$	8,673	$	12,505	$	14,091
Other non-current liabilities	$	859	$	95	$	414
Stockholders’ equity	$	11,971	$	13,979	$	11,878

^(a)  The 2019 Summarized Results of Operations include results of Plains for the period beginning January 1, 2019 through the date Occidental’s interest was sold in September 2019.

^(b)  The 2019 Summarized Balance Sheet included the balance of WES due to the loss of control on December 30, 2019 and excluded the balances of Plains as the interest was sold in September 2019.

RELATED-PARTY TRANSACTIONS

From time to time, Occidental purchases oil, NGL, power, steam and chemicals from and sells oil, NGL, natural gas, chemicals and power to certain of its equity investees and other related parties. During 2019, 2018 and 2017, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties for the years ended December 31:

millions	2019		2018		2017
Sales (a,c)	$	691	$	805	$	636
Purchases (b,c)	$	463	$	502	$	387
Services	$	28	$	52	$	38
Advances and amounts due from related parties	$	133	$	63	$	63
Amounts due to related parties (d)	$	463	$	46	$	45

^(a)  In 2019, 2018 and 2017, sales of Occidental-produced oil and NGL to Plains Pipeline affiliates accounted for 87 percent, 89 percent and 86 percent of these totals, respectively. In September 2019, Occidental sold its remaining interest in Plains Pipeline.

^(b)  In 2019 and 2018, purchases of ethylene from the Ingleside ethylene cracker accounted for 98 percent of related-party purchases, respectively.

^(c)  Excluded sales to and purchases from WES as it was a consolidated subsidiary from the date of the Acquisition through December 31, 2019.

^(d) 

Amounts due to related parties at December 31, 2019 primarily consists of a 6.5% note payable to WES due 2038.

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INCOME TAXES

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

NOTE 12 - INCOME TAXES

The following summarizes domestic and foreign components of income (loss) from continuing operations before domestic and foreign income taxes for the years ended December 31:

millions	2019			2018		2017
Domestic	$	(1,632	)	$	3,431	$	(609	)
Foreign	1,818			2,177		1,937
Total	$	186		$	5,608	$	1,328

The following summarizes components of income tax expense (benefit) on continuing operations for the years ended December 31:

millions	2019			2018			2017
Current
Federal	$	33		$	(23	)	$	(81	)
State and Local	46			52			11
Foreign	1,641			1,077			806
Total current tax expense	$	1,720		$	1,106		$	736
Deferred
Federal	(130		)	422			(856		)
State and Local	17			12			23
Foreign	(914		)	(63		)	114
Total deferred tax expense (benefit)	$	(1,027	)	$	371		$	(719	)
Total income tax expense	$	693		$	1,477		$	17

The following reconciliation of the U.S federal statutory income tax rate to Occidental’s worldwide effective tax rate on income from continuing operations for the years ended December 31 is stated as a percentage of income (loss) from continuing operations before income taxes:

	2019		2018		2017
U.S. federal statutory tax rate	21	%	21	%	35	%
Enhanced oil recovery credit and other general business credits	(4	)	(3	)	(9	)
Change in federal income tax rate	—		—		(44	)
Tax (benefit) expense due to reversal of indefinite reinvestment assertion	—		(2	)	7
Tax impact from foreign operations	187		11		12
State income taxes, net of federal benefit	28		1		2
Uncertain tax positions	13		—		—
Transaction costs	19		—		—
Non-controlling interest	(16	)	—		—
Executive compensation limitation	24		—		—
Stock warrants	(9	)	—		—
WES loss of control	113		—		—
Other	(3	)	(2	)	(2	)
Worldwide effective tax rate	373	%	26	%	1	%

In 2019, Occidental’s worldwide effective tax rate was 373%, which was largely a result of Acquisition-related costs and charges associated with the loss of control of WES for which Occidental received no tax benefit.

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2019, and 2018 were as follows:

millions	2019			2018
Deferred tax liabilities
Property, plant and equipment differences	$	(12,375	)	$	(2,089	)
Equity investments, partnerships and foreign subsidiaries	(989		)	(161		)
Gross long-term deferred tax liabilities	(13,364		)	(2,250		)
Deferred tax assets
Environmental reserves	261			195
Postretirement benefit accruals	441			176
Deferred compensation and benefits	266			170
Asset retirement obligations	906			280
Foreign tax credit carryforwards	4,379			2,356
General business credit carryforwards	443			429
Net operating loss carryforward	692			29
Interest expense carryforward	492			—
All other	782			111
Gross long-term deferred tax assets	8,662			3,746
Valuation allowance	(4,959		)	(2,403		)
Net long-term deferred tax assets	$	3,703		$	1,343
Less: Foreign deferred tax asset in long-term receivables and other assets, net	$	(56	)	$	—
Total deferred income taxes, net	$	(9,717	)	$	(907	)

Total deferred tax assets, after valuation allowances, were $3.7 billion and $1.3 billion as of December 31, 2019, and 2018, respectively. Occidental expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The total deferred tax liabilities were $13.4 billion and $2.3 billion as

of December 31, 2019 and 2018, respectively. The increase in net deferred tax liability in 2019 over 2018 is primarily due to the acquisition of Anadarko offset by the generation of interest expense and operating loss carryforwards in 2019.

As of December 31, 2019, Occidental had foreign tax credit carryforwards of $4.4 billion, federal general business credits carryforwards of $404 million, tax-effected foreign net operating loss carryforwards of $209 million, tax-effected state operating loss carryforwards of $292 million and state tax credit carryforwards of $39 million. These carryforward balances have varying carryforward periods through 2039. Occidental has recorded a valuation allowance for all of the foreign tax credit carryforwards, $240 million of the tax-effected state net operating loss carryforwards $32 million of the state tax credit carryforwards and all of the tax-effected foreign net operating loss carryforwards.

A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated international subsidiaries aggregating approximately $889 million at December 31, 2019, as it is Occidental’s intention to reinvest such earnings indefinitely. If the earnings of these international subsidiaries were not indefinitely reinvested, an additional deferred tax liability of approximately $206 million would be required.

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

millions	2019		2018			2017
Balance at January 1	$	—	$	22		$	22
Increase related to Anadarko Acquisition	2,143		—			—
Increases related to current-year positions	30		—			—
Settlements	—		(22		)	—
Balance at December 31	$	2,173	$	—		$	22

The December 31, 2019 balance of unrecognized tax benefits of $2.2 billion included potential benefits of $2.0 billion of which, if recognized, $1.7 billion would affect the effective tax rate on income. Also included are benefits of $131 million related to tax positions for which the ultimate deductibility is highly certain, but the timing of such deductibility is uncertain. Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes. The Company accrued approximately $199 million of interest related to liabilities for unrecognized tax benefits as of December 31, 2019. During 2019, Occidental recorded interest related to liabilities for unrecognized tax benefits of $30 million. There were no interest and penalties associated with liabilities for unrecognized tax benefits recorded for the years ended December 31, 2018 and 2017. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $100 million to $110 million due to settlements with taxing authorities or lapse in statutes of limitation.

Occidental has recognized $86 million and $68 million in federal and state income tax receivables at December 31, 2019, and 2018, respectively, which was recorded in other current assets. In addition, Occidental has recognized $36 million and $68 million in federal alternative minimum tax non-current receivables at December 31, 2019, and 2018, respectively, which was recorded in long-term receivables and other assets, net.

Occidental is subject to audit by various tax authorities in varying periods. See Note 11 - Lawsuits, Claims, Commitments and Contingencies for a discussion of these matters.

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$ (522)	$ 4,131	$ 1,311
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations, net	15	0	0
Depreciation, depletion and amortization of assets	5,981	3,977	4,002
Deferred income tax (benefit) provision	(1,027)	371	(719)
Other noncash charges to income	940	34	219
Asset impairments and other charges	1,328	561	545
Gain on sales of equity investments and other assets, net	(622)	(974)	(667)
Undistributed earnings from affiliates	(50)	(43)	(68)
Dry hole expense	89	56	51
Increase in receivables
Increase in receivables	(44)	(740)	(158)
Decrease (increase) in inventories	77	(108)	(349)
Decrease in other current assets	186	94	39
(Decrease) increase in accounts payable and accrued liabilities	793	195	(89)
Increase in current domestic and foreign income taxes	59	38	64
Other operating, net	0	77	680
Operating cash flow from continuing operations	7,203	7,669	4,861
Operating cash flow from discontinued operations, net of taxes	172	0	0
Net cash provided by operating activities	7,375	7,669	4,861
Capital expenditures
Capital expenditures	(6,355)	(4,975)	(3,599)
Change in capital accrual	(282)	55	122
Purchase of businesses and assets, net	(28,088)	(928)	(1,064)
Proceeds from sale of assets and equity investments, net	6,143	2,824	1,403
Equity investments and other, net	(291)	(182)	59
Investing cash flow from continuing operations	(28,873)	(3,206)	(3,079)
Investing cash flow from discontinued operations	(154)	0	0
Net cash used by investing activities	(29,027)	(3,206)	(3,079)
Proceeds from long-term debt, net - Occidental
Proceeds from long-term debt, net	21,557	978	0
Proceeds from issuance of common and preferred stock	10,028	33	28
Purchases of treasury stock	(237)	(1,248)	(25)
Cash dividends paid	(2,624)	(2,374)	(2,346)
Distributions to noncontrolling interest	(257)	0	0
Other financing, net	229	9	0
Financing cash flow from continuing operations	22,196	(3,102)	(2,343)
Financing cash flow from discontinued operations	(3)	0	0
Net cash provided (used) by financing activities	22,193	(3,102)	(2,343)
Increase (decrease) in cash, cash equivalents, restricted cash and restricted cash equivalents	541	1,361	(561)
Cash and cash equivalents — beginning of year	3,033	1,672	2,233
Cash, cash equivalents, restricted cash and restricted cash equivalents — end of year	3,574	3,033	1,672
WES
Proceeds from long-term debt, net - Occidental
Proceeds from long-term debt, net	1,459	0	0
Payments of long-term debt, net	(1,000)	0	0
Occidental
Proceeds from long-term debt, net - Occidental
Payments of long-term debt, net	$ (6,959)	$ (500)	$ 0

XML

Cover Page - USD ($)
$ in Billions

12 Months Ended

Dec. 31, 2019

Jan. 31, 2020

Jun. 28, 2019

Cover page.

Document Type

10-K

Document Annual Report

true

Document Transition Report

false

Document Period End Date

Dec. 31, 2019

Entity File Number

1-9210

Entity Registrant Name

OCCIDENTAL PETROLEUM CORP /DE/

Amendment Flag

false

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Current Fiscal Year End Date

--12-31

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

95-4035997

Entity Address, Address Line One

5 Greenway Plaza, Suite 110

Entity Address, City or Town

Houston,

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

77046

City Area Code

(713)

Local Phone Number

215-7000

Entity Central Index Key

0000797468

Title of 12(b) Security

Common Stock, $0.20 par value

Trading Symbol

OXY

Security Exchange Name

NYSE

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Emerging Growth Company

false

Entity Small Business

false

Entity Shell Company

false

Entity Public Float

$ 45.0

Entity Common Stock, Shares Outstanding

895,224,961

Documents Incorporated by Reference

Portions of the registrant’s definitive Proxy Statement, relating to its 2020 Annual Meeting of Stockholders, are incorporated by reference into Part III of this Form 10-K.

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (522)	$ 4,131	$ 1,311
Other comprehensive income (loss) items:
Foreign currency translation gains		0	0	3
Unrealized gains (losses) on derivatives	[1]	(129)	(6)	13
Pension and postretirement gains (losses)	[2]	78	137	(7)
Reclassification of realized losses (gains) on derivatives	[3]	2	13	(1)
Other comprehensive income (loss), net of tax		(49)	144	8
Comprehensive income (loss)		(571)	4,275	1,319
Less: Comprehensive income attributable to noncontrolling interests		(145)	0	0
Comprehensive income (loss) attributable to preferred and common stockholders		$ (716)	$ 4,275	$ 1,319

[1] Net of tax of $36, $2 and $(7) in 2019, 2018 and 2017, respectively.

[2] Net of tax of $(25), $(38) and $4 in 2019, 2018 and 2017, respectively. See Note 15 - Retirement and Postretirement Benefit Plans in the Notes to Consolidated Financial Statements for additional information.

[3] Net of tax of $0, $(4) and $0 in 2019, 2018 and 2017, respectively.

XML

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS - OBLIGATIONS AND FUNDED STATUS (Details) - USD ($) $ in Millions			12 Months Ended
	Aug. 08, 2019	Aug. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Amounts recognized in the consolidated balance sheet:
Deferred credits and other liabilities — pension and postretirement obligations			$ (1,807)	$ (809)
Changes in the benefit obligation:
Plan amendments		$ (178)
Pension Benefits
Amounts recognized in the consolidated balance sheet:
Long-term receivables and other assets, net			85	60
Accrued liabilities			(96)	(25)
Deferred credits and other liabilities — pension and postretirement obligations			(704)	(46)
Total amount recognized in consolidated balance sheet			(715)	(11)
Accumulated other comprehensive loss included the following after-tax balances:
Net loss			(25)	91
Prior service cost			0	0
AOCI after-tax balances			(25)	91
Changes in the benefit obligation:
Benefit obligation — beginning of year			349	391
Service cost — benefits earned during the period			45	5	$ 6
Interest cost on projected benefit obligation			39	15	17
Actuarial (gain) loss			(33)	(19)
Foreign currency exchange rate gain			0	(3)
Curtailment (gain) loss			(136)	0
Special termination benefits			49	0
Benefits paid			(95)	(40)
Participant contributions			0	0
Plan amendments			0	0
Additions due to the Acquisition	$ 193		2,136	0
Benefit obligation — end of year			2,354	349	391
Changes in plan assets:
Fair value of plan assets — beginning of year			338	403
Actual return on plan assets			122	(33)
Participant contributions			0	0
Employer contributions			41	8
Benefits paid			(95)	(40)
Additions due to the Acquisition			1,233	0
Fair value of plan assets — end of year			1,639	338	403
Unfunded status:			(715)	(11)
Accumulated Benefit Obligation in Excess of Plan Assets
Projected benefit obligation			2,175	173
Accumulated benefit obligation			1,918	169
Fair value of plan assets			1,375	98
Plan Assets in Excess of Accumulated Benefit Obligation
Projected benefit obligation			179	176
Accumulated benefit obligation			179	176
Fair value of plan assets			264	240
Postretirement Benefits
Amounts recognized in the consolidated balance sheet:
Long-term receivables and other assets, net			0	0
Accrued liabilities			(72)	(45)
Deferred credits and other liabilities — pension and postretirement obligations			(1,103)	(763)
Total amount recognized in consolidated balance sheet			(1,175)	(808)
Accumulated other comprehensive loss included the following after-tax balances:
Net loss			184	151
Prior service cost			(67)	(72)
AOCI after-tax balances			117	79
Changes in the benefit obligation:
Benefit obligation — beginning of year			808	999
Service cost — benefits earned during the period			24	23	21
Interest cost on projected benefit obligation			36	34	38
Actuarial (gain) loss			45	(90)
Foreign currency exchange rate gain			0	0
Curtailment (gain) loss			10	0
Special termination benefits			0	0
Benefits paid			(51)	(57)
Participant contributions			2	0
Plan amendments			0	(101)
Additions due to the Acquisition			301	0
Benefit obligation — end of year			1,175	808	999
Changes in plan assets:
Fair value of plan assets — beginning of year			0	0
Actual return on plan assets			0	0
Participant contributions			2	0
Employer contributions			49	0
Benefits paid			(51)	0
Additions due to the Acquisition			0	0
Fair value of plan assets — end of year			0	0	$ 0
Unfunded status:			$ (1,175)	$ (808)

XML

REVENUE - RECONCILIATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Revenue from customers	$ 18,674	$ 15,560
All other revenue	1,719	2,264
Net sales	$ 20,393	$ 17,824	$ 12,508

XML

ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS - NARRATIVE (Details) ft² in Thousands, $ in Millions		1 Months Ended							3 Months Ended		12 Months Ended
	Sep. 23, 2019 USD ($)	Dec. 31, 2019 USD ($)	Nov. 30, 2019 USD ($) ft²	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Jul. 31, 2018 USD ($)	Mar. 31, 2018 USD ($)	Apr. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($) divestiture	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Aug. 08, 2019 USD ($)
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Proceeds from real estate assets disposed		$ 565
Finance lease		$ 398									$ 398			$ 86
Acquisition cost											$ 6,441	$ 5,020	$ 3,651
Seminole-San Andres EOR
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Cost of acquired business assets										$ 600
Previously Leased Power And Steam Cogeneration Facility
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Acquisition cost						$ 443
Ecopetrol Joint Venture
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Area of development in joint venture | ft²			97
Ownership percentage in joint venture			51.00%
Plains All American Pipeline, LP
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Net proceeds from sale of equity investment				$ 646
Pre-tax gain on sale of equity investment	$ 114
Ecopetrol | Ecopetrol Joint Venture
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Amount due at closing			$ 750
Carried capital			$ 750
Minority interest in new venture			49.00%
Gain on sale			$ 563
Percentage share of capital expenditures			75.00%
Share of capital expenditures (up to)			$ 750
Failed Sale-Leaseback
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Lease term		13 years									13 years
Finance lease		$ 300									$ 300
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Non Core Midstream Assets
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Sale consideration					$ 2,600		$ 150
Proceeds received for divested assets					2,400
Pre-tax net gain from divestiture					$ 907		$ 43
Disposed of by sale | Mozambique LNG Assets
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Sale consideration				$ 4,200
Disposed of by sale | Non-strategic acreage in Permian Basin Counties
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Sale consideration										$ 600
Number of divestitures of non-strategic acreage | divestiture										2
Pre-tax gain on disposal										$ 81
Disposed of by sale | Non-core Permian acreage
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Sale consideration									$ 90				90
Pre-tax gain on disposal									55
Disposed of by sale | South Texas operations
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Sale consideration								$ 500
Pre-tax gain on disposal								$ 500
Assets held for sale | Non-core Permian acreage
ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS
Sale consideration									$ 500				$ 500

XML

INCOME TAXES - RECONCILIATION OF UNRECOGNIZED TAX BENEFITS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, at beginning of period	$ 0	$ 22	$ 22
Increase related to Anadarko Acquisition	2,143	0	0
Increases related to current-year positions	30	0	0
Settlements	0	(22)	0
Balance, at end of period	$ 2,173	$ 0	$ 22

XML

STOCKHOLDERS' EQUITY (Tables)

12 Months Ended

Dec. 31, 2019

Stockholders' Equity Note [Abstract]

Summary of common stock issuances

The following is a summary of common stock issuances:

Shares in thousands	Common Stock
Balance, December 31, 2016	892,215
Issued	1,252
Options exercised and other, net	2
Balance, December 31, 2017	893,469
Issued	1,628
Options exercised and other, net	19
Balance, December 31, 2018	895,116
Issued in the ordinary course	3,188
Issued as part of the Acquisition (a)	146,131
Balance, December 31, 2019	1,044,435

^(a) 

Included approximately 2 million shares of common stock issued to a benefits trust for former Anadarko employees treated as treasury stock at December 31, 2019.

Calculation of basic and diluted EPS

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

millions except per share amounts	2019			2018			2017
Income (loss) from continuing operations	$	(507	)	$	4,131		$	1,311
Loss from discontinued operations	(15		)	—			—
Net income (loss)	$	(522	)	$	4,131		$	1,311
Less: Net income attributable to noncontrolling interest	(145		)	—			—
Less: Preferred stock dividends	(318		)	—			—
Net income (loss) attributable to common stock	$	(985	)	$	4,131		$	1,311
Less: Net income allocated to participating securities	—			(17		)	(6		)
Net income (loss), net of participating securities	$	(985	)	$	4,114		$	1,305
Weighted-average number of basic shares	809.5			761.7			765.1
Basic earnings (loss) per common share	$	(1.22	)	$	5.40		$	1.71
Net income (loss), net of participating securities	$	(985	)	$	4,114		$	1,305
Weighted-average number of basic shares	809.5			761.7			765.1
Dilutive securities	—			1.6			0.8
Total diluted weighted-average common shares	809.5			763.3			765.9
Diluted earnings (loss) per common share	$	(1.22	)	$	5.39		$	1.70

Components of accumulated other comprehensive loss

Accumulated other comprehensive loss consisted of the following after-tax amounts at December 31:

millions	2019			2018
Foreign currency translation adjustments	$	(7	)	$	(7	)
Unrealized gains (losses) on derivatives	(122		)	5
Pension and postretirement adjustments (a)	(92		)	(170		)
Total	$	(221	)	$	(172	)

^(a) 

See Note 15 - Retirement and Postretirement Benefit Plans for further information.

XML

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Assets and liabilities measured at fair value on a recurring basis

The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis:

millions	Fair Value Measurements Using								Total Fair Value
Balance Sheet Classification	Level 1		Level 2		Level 3		Netting
December 31, 2019
Embedded Derivatives
Accrued liabilities	$	—	$	40	$	—	$	—	$	40
Deferred credits and other liabilities - other	$	—	$	49	$	—	$	—	$	49
December 31, 2018
Embedded Derivatives
Accrued liabilities	$	—	$	66	$	—	$	—	$	66
Deferred credits and other liabilities - other	$	—	$	116	$	—	$	—	$	116

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CASH EQUIVALENTS AND RESTRICTED CASH EQUIVALENTS (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 3,032	$ 3,033
Restricted cash and restricted cash equivalents	480	0
Cash and restricted cash included in assets held for sale	8
Restricted cash and restricted cash equivalents included in long-term receivables and other assets, net	54
Cash, cash equivalents, restricted cash, and restricted cash equivalents	$ 3,574	$ 3,033	$ 1,672	$ 2,233

XML

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

NOTE 15 - RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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

In conjunction with the Acquisition, Occidental acquired certain Anadarko contributory and non-contributory defined benefit pension plans, which include both qualified and supplemental plans, and plans that provide health care and life insurance benefits for certain retired employees. The Anadarko pension and postretirement obligations were remeasured as of the Acquisition date. The remeasurement resulted in an increase to the benefit obligation of $193 million. The disclosures below exclude the plans related to the Africa Assets classified as held for sale as of December 31, 2019.

During the third quarter of 2018, Occidental adopted a postretirement benefit plan design change, which replaced the previous self-insured benefit with a Medicare Advantage PPA plan for Medicare-eligible retirees. As a result of this change, the postretirement benefit obligation was remeasured as of August 31, 2018. The remeasurement resulted in a decrease to the benefit obligation of $178 million with a corresponding offset to accumulated other comprehensive income.

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, 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 $279 million and $201 million as of December 31, 2019, and 2018, respectively, and Occidental expensed $211 million in 2019, $152 million in 2018 and $130 million in 2017 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited. Approximately 4,000 domestic and 600 foreign national employees, mainly union, nonunion hourly and certain employees that joined Occidental from acquired operations with grandfathered benefits, are currently accruing benefits under these plans.

Pension costs for Occidental’s defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.

POSTRETIREMENT AND OTHER BENEFIT PLANS

Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. Occidental generally funds the benefits as they are paid during the year. These benefit costs, including the postretirement costs, were approximately $220 million in 2019, $182 million in 2018 and $181 million in 2017.

OBLIGATIONS AND FUNDED STATUS

The following tables show the amounts recognized in Occidental’s consolidated balance sheets at December 31, 2019 and 2018, related to its pension and postretirement benefit plans:

	Pension Benefits						Postretirement Benefits
millions	2019			2018			2019			2018
Amounts recognized in the consolidated balance sheet:
Long-term receivables and other assets, net	$	85		$	60		$	—		$	—
Accrued liabilities	(96		)	(25		)	(72		)	(45		)
Deferred credits and other liabilities — pension and postretirement obligations	(704		)	(46		)	(1,103		)	(763		)
	$	(715	)	$	(11	)	$	(1,175	)	$	(808	)
Accumulated other comprehensive loss included the following after-tax balances:
Net (gain) loss	$	(25	)	$	91		$	184		$	151
Prior service credit	—			—			(67		)	(72		)
	$	(25	)	$	91		$	117		$	79

The following tables show the funding status, obligations and plan asset fair values of Occidental related to its pension and postretirement benefit plans for the years ended December 31:

	Pension Benefits						Postretirement Benefits
millions	2019			2018			2019			2018
Changes in the benefit obligation:
Benefit obligation — beginning of year	$	349		$	391		$	808		$	999
Service cost — benefits earned during the period	45			5			24			23
Interest cost on projected benefit obligation	39			15			36			34
Actuarial (gain) loss	(33		)	(19		)	45			(90		)
Foreign currency exchange rate gain	—			(3		)	—			—
Curtailment (gain) loss	(136		)	—			10			—
Special termination benefits	49			—			—			—
Benefits paid	(95		)	(40		)	(51		)	(57		)
Participant contributions	—			—			2			—
Plan amendments	—			—			—			(101		)
Additions due to the Acquisition	2,136			—			301			—
Benefit obligation — end of year	$	2,354		$	349		$	1,175		$	808
Changes in plan assets:
Fair value of plan assets — beginning of year	$	338		$	403		$	—		$	—
Actual return on plan assets	122			(33		)	—			—
Participant contributions	—			—			2			—
Employer contributions	41			8			49			—
Benefits paid	(95		)	(40		)	(51		)	—
Additions due to the Acquisition	1,233			—			—			—
Fair value of plan assets — end of year	$	1,639		$	338		$	—		$	—
Unfunded status:	$	(715	)	$	(11	)	$	(1,175	)	$	(808	)

The following table sets forth details of the obligations and assets of Occidental’s defined benefit pension plans for the years December 31:

	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
millions	2019		2018		2019		2018
Projected benefit obligation	$	2,175	$	173	$	179	$	176
Accumulated benefit obligation	$	1,918	$	169	$	179	$	176
Fair value of plan assets	$	1,375	$	98	$	264	$	240

COMPONENTS OF NET PERIODIC BENEFIT COST

The following table sets forth the components of net periodic benefit costs for the years ended December 31:

	Pension Benefits									Postretirement Benefits
millions	2019			2018			2017			2019			2018			2017
Net periodic benefit costs:
Service cost — benefits earned during the period	$	45		$	5		$	6		$	24		$	23		$	21
Interest cost on projected benefit obligation	39			15			17			36			34			38
Expected return on plan assets	(50		)	(25		)	(24		)	—			—			—
Recognized actuarial loss	9			7			10			8			14			14
Recognized prior service credit	—			—			—			(8		)	—			—
Liability (gain) loss due to curtailment	(91		)	—			—			6			—			—
Special termination benefits	49			—			—			—			—			—
Other costs and adjustments	(2		)	1			3			—			(2		)	1
Net periodic benefit cost	$	(1	)	$	3		$	12		$	66		$	69		$	74

The service cost component of net periodic benefit cost is included in selling, general and administrative, oil and gas operating expense, chemical and midstream costs, and exploration expense on Occidental’s Consolidated Statements of Operations. All other components of net periodic benefit cost are included in other operating and non-operating expense.

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from Accumulated Other Comprehensive Income (AOCI) into net periodic benefit cost over the next fiscal year are $3 million and zero, respectively. The estimated net loss and prior service credit for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $12 million and $(8) 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 for the years ended December 31:

	Pension Benefits				Postretirement Benefits
	2019		2018		2019		2018
Benefit Obligation Assumptions:
Discount rate	3.10	%	4.09	%	3.26	%	4.29	%
Net Periodic Benefit Cost Assumptions:
Discount rate for January 1 - August 31 expense	3.21	%	3.45	%	3.41	%	3.61	%
Discount rate for September 1 - December 31 expense	3.21	%	3.45	%	3.41	%	4.14	%
Assumed long-term rate of return on assets	6.50	%	6.50	%	—		—
Rates of increase in compensation levels	5.44	%	—		—		—

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on AA-AAA Universe yield curve in 2019 and 2018. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end. Assumed rates of compensation increases for active participants in certain plans and vary by age group.

In 2019, Occidental adopted the Society of Actuaries 2019 Pri-2012 Private Retirement Plans Mortality Tables with Mortality Improvement Scale, which updated the mortality assumptions that private defined-benefit plans in the United States use in the actuarial valuations that determine a plan sponsor’s pension obligations. The new mortality assumption reflects additional data that the Social Security Administration has released since the previous mortality tables and improvement scales were released. This additional data shows a lower degree of mortality improvement than previously reflected. The changes in the mortality assumption results in a decrease of $15 million and $9 million in the pension and postretirement benefit obligation, respectively, at December 31, 2019.

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% to 8.8% at December 31, 2019 and from 1.0% to 8.9% at December 31, 2018. The average rate of increase in future compensation levels ranged from 1.0% to 8.0% in 2019, depending on local economic conditions.

The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial

assumptions and health care cost trend rates. Health care cost trend rates for Medicare advantaged prescription drug (MAPD) plans of 4.3% to 21.5% in 2019, between (7.7)% and (6.2)% in 2020, 9.6% in 2021, then grading down to 4.5% in 2028 and beyond. The negative trend rates for the MAPD plans reflect the repeal of the Health Insurer Fee effective in 2021. Health care cost trend rates used for non-MAPD plans are 6.7% to 7.5% in 2019, then grading down to 4.5% in 2028 and beyond.

A 1% increase or a 1% decrease in these assumed health care cost trend rates would result in an increase of $131 million or a reduction of $103 million, respectively, in the postretirement benefit obligation and increase of $13 million or a reduction of $9 million in the annual service and interest costs as of December 31, 2019.

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

FAIR VALUE OF PENSION PLAN ASSETS

Pension plan assets are monitored by Occidental’s Pension and Retirement Trust and Investment Committee or by the Investment Subcommittee of the Anadarko Petroleum Corporation Administrative & Investment Committee (collectively, the Investment Committees), in their roles as fiduciaries. The Investment Committees select and employ various external professional investment management firms to manage specific investments across the spectrum of asset classes. The Investment Committees employ a total return investment approach that uses a diversified blend of investments across several categories (equity securities, fixed-income securities, real estate, hedge funds, and private equity) to optimize the long-term return of plan assets at a prudent level of risk. Equity investments are diversified across U.S. and non-U.S. stocks, as well as differing styles and market capitalizations. 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 were as follows:

millions	Level 1		Level 2		Level 3		Total
December 31, 2019
Asset Class:
U.S. government securities	$	13	$	—	$	—	$	13
Corporate bonds (a)	—		60		—		60
Mutual funds:
Bond funds	46		—		—		46
International funds	68		—		—		68
Common and preferred stocks (b)	173		—		—		173
Other	—		29		—		29
Investments measured at fair value	$	300	$	89	$	—	$	389
Investments measured at net asset value (c)	—		—		—		1,253
Total pension plan assets (d)	$	300	$	89	$	—	$	1,642
December 31, 2018
Asset Class:
U.S. government securities	$	17	$	—	$	—	$	17
Corporate bonds (a)	—		66		—		66
Common/collective trusts (e)	—		9		—		9
Mutual funds:
Bond funds	31		—		—		31
Blend funds	48		—		—		48
Common and preferred stocks (b)	141		—		—		141
Other	—		31		—		31
Total pension plan assets (d)	$	237	$	106	$	—	$	343

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

^(b)  This category included 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)  Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.

^(e)  Amounts exclude net payables of approximately $3 million and $5 million as of December 31, 2019 and 2018, respectively.

Occidental expects to contribute $179 million in cash to its defined benefit pension plans during 2020. Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows for the years ended December 31:

millions	Pension Benefits		Postretirement Benefits
2020	$	810		$	73
2021	$	113		$	72
2022	$	125		$	71
2023	$	128		$	70
2024	$	124		$	68
2025 - 2029	$	625		$	321

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LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

NOTE 11 - LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

LEGAL MATTERS

Occidental 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. Occidental or certain of its subsidiaries also are involved in proceedings under 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 Occidental 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 outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserves for matters, other than for environmental remediation, that satisfy this criteria as of December 31, 2019, and December 31, 2018, were not material to Occidental’s Consolidated Balance Sheets.

On May 30, 2019, a complaint was filed in the Court of Chancery of the State of Delaware by purported Occidental stockholders High River Limited Partnership, Icahn Partners Master Fund LP and Icahn Partners LP (the “Icahn Complainants”), captioned High River Ltd. P’ship v. Occidental Petroleum Corp., C.A. No. 2019-0403-JRS, seeking inspection of Occidental’s books and records pursuant to Section 220 of the Delaware General Corporation Law. In the complaint, the Icahn Complainants noted that they had accumulated over $1.6 billion of Occidental Common Stock. On June 14, 2019, Occidental filed an answer to the complaint in the Court of Chancery of the State of Delaware. A trial was held on September 20, 2019, and the court dismissed the Icahn Complaint. The Icahn Complainants appealed and oral arguments occurred in February 2020.

In 2016, Occidental received payments from the Republic of Ecuador of approximately $1.0 billion pursuant to a November 2015 arbitration award for Ecuador’s 2006 expropriation of Occidental’s Participation Contract for Block 15. The awarded amount represented a recovery of 60 percent of the value of Block 15. In 2017, Andes Petroleum Ecuador Ltd. (Andes) filed a demand for arbitration, claiming it is entitled to a 40 percent share of the judgment amount obtained by Occidental. Occidental contends that Andes is not entitled to any of the amounts paid under the 2015 arbitration award because Occidental’s recovery was limited to Occidental’s own 60 percent economic interest in the block. The merits hearing is scheduled for May 2020. Occidental intends to vigorously defend against this claim in arbitration.

The ultimate outcome and impact of outstanding lawsuits, claims and proceedings on Occidental cannot be predicted. Management believes that the resolution of these matters will not, individually or in the aggregate, have a material adverse effect on Occidental’s Consolidated Balance Sheets. If unfavorable outcomes of these matters were to occur, future results of operations or cash flows for any particular quarterly or annual period could be materially adversely affected. Occidental’s estimates are based on information known about the legal matters and its experience in contesting, litigating and settling similar matters. 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. Taxable years through 2016 for U.S. federal income tax purposes have been audited by the U.S. Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program and subsequent taxable years are currently under review. Taxable years through 2009 have been audited for state income tax purposes. While a single foreign tax jurisdiction is open for 2002, all other significant audit matters in foreign jurisdictions have been resolved through 2010. 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.

For Anadarko, its taxable years through 2016 for U.S. federal and state income tax purposes have been audited by the IRS and respective state taxing authorities. There are outstanding significant audit matters in one foreign jurisdiction. During the course of the tax audit, disputes have arisen and other disputes may arise as to facts and matters of law. Other than the matter discussed below, Occidental believes that the resolution of these outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.

Anadarko received an $881 million tentative refund in 2016 related to its $5.2 billion Tronox settlement payment in 2015. In September 2018, Anadarko received a statutory notice of deficiency from the IRS disallowing the net operating loss carryback and rejecting Anadarko’s refund claim. As a result, Anadarko filed a petition with the U.S. Tax Court to dispute the disallowances in November 2018. The case is currently in the IRS appeals process. If the matter is not resolved in the IRS appeals process, Occidental expects to continue pursuing resolution in the U.S. Tax Court.

While Occidental believes it is entitled to this refund, in accordance with ASC 740’s guidance on the accounting for uncertain tax positions, as of December 31, 2019, Occidental has recorded no tax benefit on the tentative cash tax refund of

$881 million. As a result, should Occidental not ultimately prevail on the issue, there would be no additional tax expense recorded for financial statement purposes other than future interest. However, in that event Occidental would be required to repay approximately $925 million ($898 million federal and $27 million in state taxes) plus accrued interest of approximately $189 million. As a result, a liability for this amount has been recorded in deferred credits and other liabilities - other at December 31, 2019.

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, 2019, 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.

PURCHASE OBLIGATIONS AND COMMITMENTS

Occidental, 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, 2019, total purchase obligations were $20.7 billion, which included approximately $3.3 billion in 2020, $5.7 billion in 2021 and 2022, $4.7 billion in 2023 and 2024, and $7.1 billion in 2025 and thereafter.

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2019

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

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

			Additions
millions	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions (a)			Balance at End of Period
2019
Allowance for doubtful accounts	$	668	$	126	$	(6	)	$	—		$	788	(b)
Environmental, litigation and other reserves	$	994	$	182	$	1,408		$	(173	)	$	2,411	(c)
2018
Allowance for doubtful accounts	$	594	$	77	$	(3	)	$	—		$	668	(b)
Environmental, litigation, tax and other reserves	$	935	$	140	$	85		$	(166	)	$	994	(c)
2017
Allowance for doubtful accounts	$	558	$	37	$	(2	)	$	1		$	594	(b)
Environmental, litigation, tax and other reserves	$	997	$	45	$	53		$	(160	)	$	935	(c)

Note:  The amounts presented represent continuing operations.

^(a)  Primarily represents payments.

^(b)  Of these amounts, $22 million, $24 million and $18 million in 2019, 2018, and 2017, respectively, are classified as current.

^(c) 

Of these amounts, $188 million, $146 million and $163 million in 2019, 2018, and 2017, respectively, are classified as current.

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Consolidated Statements of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUES AND OTHER INCOME
Net sales	$ 20,393	$ 17,824	$ 12,508
Interest, dividends and other income	217	136	99
Gains on sale of equity investments and other assets, net	622	974	667
Total	21,232	18,934	13,274
COSTS AND OTHER DEDUCTIONS
Oil and gas operating expense	3,246	2,761	2,427
Transportation expense	621	152	175
Chemical and midstream cost of sales	2,791	2,833	2,938
Purchased commodities	1,679	822	54
Selling, general and administrative	882	585	546
Other operating and non-operating expense	1,425	1,028	878
Depreciation, depletion and amortization	5,981	3,977	4,002
Asset impairments and other charges	1,361	561	545
Taxes other than on income	707	439	311
Anadarko acquisition-related costs	1,647	0	0
Exploration expense	246	110	82
Interest and debt expense, net	1,066	389	345
Total	21,652	13,657	12,303
Income (loss) before income taxes and other items	(420)	5,277	971
OTHER ITEMS
Gains on interest rate swaps and warrants, net	233	0	0
Income from equity investments	373	331	357
Total	606	331	357
Income from continuing operations before income taxes	186	5,608	1,328
Income tax expense	(693)	(1,477)	(17)
Income (loss) from continuing operations	(507)	4,131	1,311
Loss from discontinued operations, net of tax	(15)	0	0
NET INCOME (LOSS)	(522)	4,131	1,311
Less: Net income attributable to noncontrolling interest	(145)	0	0
Less: Preferred stock dividends	(318)	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (985)	$ 4,131	$ 1,311
PER COMMON SHARE, BASIC
Income (loss) from continuing operations—basic (in dollars per share)	$ (1.20)	$ 5.40	$ 1.71
(Loss) from discontinued operations—basic (in dollars per share)	(0.02)	0	0
Net income (loss) attributable to common stockholders—basic (in dollars per share)	(1.22)	5.40	1.71
PER COMMON SHARE, DILUTED
Income (loss) from continuing operations—diluted (in dollars per share)	(1.20)	5.39	1.70
(Loss) from discontinued operations—diluted (in dollars per share)	(0.02)	0	0
Net income (loss) attributable to common stockholders—diluted (in dollars per share)	(1.22)	5.39	1.70
DIVIDENDS PER COMMON SHARE (in dollars per share)	$ 3.14	$ 3.10	$ 3.06

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Consolidated Statements of Stockholders' Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2019 $ / shares
Statement of Stockholders' Equity [Abstract]
Dividends on common stock (in dollars per share)	$ 3.14
Dividends on preferred stock (in dollars per share)	$ 3,489

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS - NARRATIVE (Details) $ in Millions			12 Months Ended
	Aug. 08, 2019 USD ($)	Aug. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) employee	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Defined Benefit Plan Disclosure
Decrease to benefit obligation		$ 178
Accrued liabilities for the supplemental retirement plan			$ 279	$ 201
Expenses under provisions of defined contribution and supplemental retirement plans			211	152	$ 130
Total benefit costs, including postretirement costs			$ 220	182	$ 181
United States
Defined Benefit Plan Disclosure
Number of employees accruing benefits under defined benefit plans | employee			4,000
Foreign
Defined Benefit Plan Disclosure
Number of employees accruing benefits under defined benefit plans | employee			600
Pension Benefits
Defined Benefit Plan Disclosure
Additions due to the Acquisition	$ 193		$ 2,136	0
Decrease to benefit obligation			$ 0	$ 0

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REVENUE - IMPACT OF ADOPTION (Details)	12 Months Ended
	Dec. 31, 2019
Low end of range
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract term	1 month
High end of range
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract term	1 year

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THE ACQUISITION - MERGER-RELATED COSTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Total	$ 1,647	$ 0	$ 0
Anadarko Petroleum Corporation
Business Acquisition [Line Items]
Employee severance and related employee cost	1,033
Licensing fees for critical seismic data	401
Bank, legal, consulting and other	213
Total	$ 1,647

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INCOME TAXES - NARRATIVE (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Worldwide effective tax rate	373.00%	26.00%	1.00%
Total deferred tax assets, after valuation allowances	$ 3,703,000,000	$ 1,343,000,000
Total deferred tax liabilities	13,364,000,000	2,250,000,000
Deferred foreign tax liability due to reversal of indefinite re-investment assertion	889,000,000
Additional deferred tax liability amount required	206,000,000
Unrecognized tax benefits	2,173,000,000	0	$ 22,000,000	$ 22,000,000
Potential benefit	2,000,000,000.0
Potential benefit, if recognized, would affect the effective tax rate on income	1,700,000,000
Benefits related to tax positions which ultimate deductibility is highly certain	131,000,000
Interest accrued related to liabilities for unrecognized tax benefits	199,000,000
Interest related to liabilities for unrecognized tax benefits	30,000,000
Interest and penalties associated with liabilities for unrecognized tax benefits		0	$ 0
Low end of range
Income Tax Contingency [Line Items]
Possible decrease to unrecognized tax benefit due to settlements with taxing authorities	100,000,000
High end of range
Income Tax Contingency [Line Items]
Possible decrease to unrecognized tax benefit due to settlements with taxing authorities	110,000,000
Other current assets
Income Tax Contingency [Line Items]
Income tax receivables	86,000,000	68,000,000
Long-term receivables and other assets, net
Income Tax Contingency [Line Items]
Federal alternative minimum tax non-current receivables	36,000,000	$ 68,000,000
Foreign
Income Tax Contingency [Line Items]
Tax credit carryforwards	4,400,000,000
Operating loss carryforwards	209,000,000
State
Income Tax Contingency [Line Items]
Tax credit carryforwards	39,000,000
Operating loss carryforwards	292,000,000
Operating loss carryforward, valuation allowance	240,000,000
Tax credit carryforward, valuation allowance	32,000,000
General business credits
Income Tax Contingency [Line Items]
Tax credit carryforwards	$ 404,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CASH (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Trade receivables, net	$ 6,373	$ 4,893

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STOCK-BASED INCENTIVE PLANS (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

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

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2019, is presented below:

	Cash-Settled					Stock-Settled
thousands, except fair values	RSUs		Weighted-Average Grant-Date Fair Value			RSUs		Weighted-Average Grant-Date Fair Value
Unvested at January 1	186			$	73.93	3,971			$	73.19
Granted (a)	4,267			$	42.62	3,543			$	58.73
Vested	(67	)		$	72.26	(2,743	)		$	67.04
Forfeitures	(39	)		$	47.60	(376	)		$	67.25
Unvested at December 31	4,347			$	43.46	4,395			$	65.88

^(a) 

Included 1.5 million shares issued in exchange for Anadarko stock-based incentive shares.

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

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

	TSRIs
	2019			2018			2017
Assumptions used:
Risk-free interest rate	2.5		%	2.3		%	1.5		%
Volatility factor	22		%	24		%	25		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	67.19		$	69.87		$	67.21

Summary of the changes of awards

	CROCEI, ROCEI, and ROAI
thousands, except fair values	Awards		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	210			$	71.60
Granted	81			$	67.19
Vested (a)	(137	)		$	72.54
Forfeited	—			—
Unvested at December 31	154			$	68.44

^(a) 

Presented at the target payouts. The weighted-average payout at vesting was 86% of the target resulting in the issuance of approximately 118,000 shares.

A summary of Occidental’s unvested TSRIs as of December 31, 2019 and changes during the year ended December 31, 2019 is presented below:

	TSRIs
thousands, except fair values	Awards		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	1,444			$	70.97
Granted	578			$	67.19
Vested (a)	(442	)		$	76.83
Forfeitures	(43	)		$	76.83
Unvested at December 31	1,537			$	67.70

^(a) 

Presented at the target payouts. The weighted-average payout at vesting was 19% of the target, resulting in the issuance of approximately 83,000 shares of Occidental common stock.

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Schedule of industry segments

millions	Oil and Gas			Chemical		Marketing and Midstream			Corporate and Eliminations				Total
Year ended December 31, 2019
Net sales	$	13,423		$	4,102	$	4,132		$	(1,264	)		$	20,393
Income (loss) from continuing operations before income taxes	$	2,352	(a)	$	799	$	241	(b)	$	(3,206	)	(c)	$	186
Income tax expense	—			—		—			(693		)	(d)	(693		)
Income (loss) from continuing operations	$	2,352		$	799	$	241		$	(3,899	)		$	(507	)
Investments in unconsolidated entities	$	181		$	689	$	5,519		$	—			$	6,389
Property, plant and equipment additions(e)	$	5,559		$	272	$	475		$	135			$	6,441
Depreciation, depletion and amortization	$	4,994		$	368	$	563		$	56			$	5,981
Total assets	$	77,936		$	4,361	$	17,055		$	9,978			$	109,330
Year ended December 31, 2018
Net sales	$	10,441		$	4,657	$	3,656		$	(930	)		$	17,824
Income (loss) from continuing operations before income taxes	$	2,442	(a)	$	1,159	$	2,802	(b)	$	(795	)	(c)	$	5,608
Income tax expense	—			—		—			(1,477		)	(d)	(1,477		)
Income (loss) from continuing operations	$	2,442		$	1,159	$	2,802		$	(2,272	)		$	4,131
Investments in unconsolidated entities	$	—		$	733	$	947		$	—			$	1,680
Property, plant and equipment additions(e)	$	4,443		$	277	$	221		$	79			$	5,020
Depreciation, depletion and amortization	$	3,254		$	354	$	331		$	38			$	3,977
Total assets	$	24,874		$	4,359	$	11,087		$	3,534			$	43,854
Year ended December 31, 2017
Net sales	$	7,870		$	4,355	$	1,157		$	(874	)		$	12,508
Income (loss) from continuing operations before income taxes	$	1,111	(a)	$	822	$	85	(b)	$	(690	)	(c)	$	1,328
Income tax expense	—			—		—			(17		)	(d)	(17		)
Income (loss) from continuing operations	$	1,111		$	822	$	85		$	(707	)		$	1,311
Investments in unconsolidated entities	$	—		$	771	$	739		$	5			$	1,515
Property, plant and equipment additions(e)	$	2,968		$	323	$	296		$	64			$	3,651
Depreciation, depletion and amortization	$	3,269		$	352	$	340		$	41			$	4,002
Total assets	$	23,595		$	4,364	$	11,775		$	2,292			$	42,026

^(a)  The 2019 amount included a net gain on sale of $475 million related to Occidental’s joint venture with Ecopetrol in the Midland Basin and sale of real estate assets, a $285 million impairment charge associated with domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and a $39 million charge related to Occidental’s mutually agreed early termination of its Qatar ISSD contract. The 2018 amount included $416 million for the impairment of proved oil properties and inventory in Qatar ISND and ISSD due to the decline in oil prices. The 2017 amount included pre-tax asset sale gains of $655 million primarily related to South Texas and non-core acreage in the Permian basin and $397 million for the impairment of non-core proved and unproved Permian acreage.

^(b)  The 2019 amount included a $1 billion charge as a result of recording Occidental’s investment in WES at fair value as of December 31, 2019 upon the loss of control, a $114 million gain on the sale of an equity investment in Plains and a $30 million mark-to-market gain on an interest rate swap for WES. The 2018 amount included pre-tax asset sale gains of $907 million on the sale of non-core domestic midstream assets. The 2017 amount included pre-tax charges of $120 million related to asset impairments of idled facilities.

^(c)  The 2019 amount included corporate transactions related to the Acquisition including charges of $1.0 billion related to employee severance and related costs, $401 million related to crucial seismic data and $213 million for bank, legal and consulting fees. There were no significant corporate transactions and events affecting 2018 and 2017 results. The tax effect of these pre-tax adjustments was a $245 million benefit in 2019, and $198 million expense and $392 million expense in 2018 and 2017, respectively.

^(d)  Included all foreign and domestic income taxes from continuing operations.

^(e) 

Included capital expenditures and capitalized interest, but excluded acquisition and disposition of assets.

Net sales and property, plant and equipment, net by geographic areas

	Property, plant and equipment, net
millions	2019		2018		2017
United States	$	72,808	$	23,594	$	22,863
International
United Arab Emirates	3,887		4,051		4,241
Oman	2,115		2,048		1,962
Colombia	1,010		927		807
Qatar	562		741		1,236
Other International	87		76		65
Total International	7,661		7,843		8,311
Total	$	80,469	$	31,437	$	31,174

XML

DERIVATIVES - FAIR VALUE (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Gross and net fair values of outstanding derivatives (in millions)
Collateral paid netted against derivative liabilities	$ 104
Collateral deposited with clearinghouses and brokers	65	$ 54
Oil Collars and Calls | Other current assets
Gross and net fair values of outstanding derivatives (in millions)
Netting, asset	0
Total net fair value, asset	92
Oil Collars and Calls | Other current assets | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0
Oil Collars and Calls | Other current assets | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	92
Oil Collars and Calls | Other current assets | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0
Oil Collars and Calls | Deferred credits and other liabilities - other
Gross and net fair values of outstanding derivatives (in millions)
Netting and collateral, liability	0
Total net fair value, liability	(160)
Oil Collars and Calls | Deferred credits and other liabilities - other | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0
Oil Collars and Calls | Deferred credits and other liabilities - other | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(160)
Oil Collars and Calls | Deferred credits and other liabilities - other | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0
Marketing Derivatives | Other current assets
Gross and net fair values of outstanding derivatives (in millions)
Netting, asset	(973)	(2,392)
Total net fair value, asset	51	249
Marketing Derivatives | Other current assets | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	945	2,531
Marketing Derivatives | Other current assets | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	79	110
Marketing Derivatives | Other current assets | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0	0
Marketing Derivatives | Long-term receivables and other assets, net
Gross and net fair values of outstanding derivatives (in millions)
Netting, asset	(4)	(6)
Total net fair value, asset	12	8
Marketing Derivatives | Long-term receivables and other assets, net | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	4	5
Marketing Derivatives | Long-term receivables and other assets, net | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	12	9
Marketing Derivatives | Long-term receivables and other assets, net | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0	0
Marketing Derivatives | Accrued liabilities
Gross and net fair values of outstanding derivatives (in millions)
Netting and collateral, liability	973	2,392
Total net fair value, liability	(79)	(66)
Marketing Derivatives | Accrued liabilities | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(1,008)	(2,357)
Marketing Derivatives | Accrued liabilities | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(44)	(101)
Marketing Derivatives | Accrued liabilities | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0	0
Marketing Derivatives | Deferred credits and other liabilities - other
Gross and net fair values of outstanding derivatives (in millions)
Netting and collateral, liability	4	6
Total net fair value, liability	(1)	(2)
Marketing Derivatives | Deferred credits and other liabilities - other | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(4)	(6)
Marketing Derivatives | Deferred credits and other liabilities - other | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(1)	(2)
Marketing Derivatives | Deferred credits and other liabilities - other | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0	$ 0
Interest Rate Swaps | Other current assets
Gross and net fair values of outstanding derivatives (in millions)
Netting, asset	0
Total net fair value, asset	5
Interest Rate Swaps | Other current assets | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0
Interest Rate Swaps | Other current assets | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	5
Interest Rate Swaps | Other current assets | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0
Interest Rate Swaps | Long-term receivables and other assets, net
Gross and net fair values of outstanding derivatives (in millions)
Netting, asset	0
Total net fair value, asset	5
Interest Rate Swaps | Long-term receivables and other assets, net | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0
Interest Rate Swaps | Long-term receivables and other assets, net | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	5
Interest Rate Swaps | Long-term receivables and other assets, net | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	0
Interest Rate Swaps | Accrued liabilities
Gross and net fair values of outstanding derivatives (in millions)
Netting and collateral, liability	0
Total net fair value, liability	(657)
Interest Rate Swaps | Accrued liabilities | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0
Interest Rate Swaps | Accrued liabilities | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(657)
Interest Rate Swaps | Accrued liabilities | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0
Interest Rate Swaps | Deferred credits and other liabilities - other
Gross and net fair values of outstanding derivatives (in millions)
Netting and collateral, liability	0
Total net fair value, liability	(776)
Interest Rate Swaps | Deferred credits and other liabilities - other | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0
Interest Rate Swaps | Deferred credits and other liabilities - other | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(776)
Interest Rate Swaps | Deferred credits and other liabilities - other | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0
Warrant | Deferred credits and other liabilities - other
Gross and net fair values of outstanding derivatives (in millions)
Netting and collateral, liability	0
Total net fair value, liability	(107)
Warrant | Deferred credits and other liabilities - other | Level 1
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	0
Warrant | Deferred credits and other liabilities - other | Level 2
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	(107)
Warrant | Deferred credits and other liabilities - other | Level 3
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	$ 0

XML

LONG-TERM DEBT - DEBT MATURITIES (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Principal payments on long-term debt
Aggregate future principal payments and carrying value	$ 37,400	$ 10,407
Due in 2021	6,400
Due in 2022	4,700
Due in 2023	1,200
Due in 2024 and thereafter	$ 25,100

XML

LEASE COMMITMENTS - FUTURE UNDISCOUNTED MINIMUM PAYMENTS UNDER ASC 840 (Details) $ in Millions	Dec. 31, 2018 USD ($)
Future net minimum operating lease payments
2019	$ 186
2020	147
2021	96
2022	68
2023	49
Thereafter	158
Total minimum lease payments	$ 704

XML

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES - PURCHASE OBLIGATIONS (Details) $ in Billions	Dec. 31, 2019 USD ($)
Purchase obligations
Total purchase obligations	$ 20.7
2020	3.3
2021 and 2022	5.7
2023 and 2024	4.7
2025 and thereafter	$ 7.1

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset retirement obligation
Beginning balance	$ 1,499	$ 1,312
Liabilities assumed in the Acquisition	3,344	0
Liabilities incurred – capitalized to PP&E	131	31
Liabilities settled and paid	(200)	(40)
Accretion expense	71	67
Acquisitions, dispositions and other	0	(18)
WES loss of control	(359)	0
Revisions to previous estimates	147	147
Ending balance	4,633	1,499
Asset retirement obligations, current balance included in Accrued Liabilities	$ 248	$ 75

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - PROPERTY, PLANT AND EQUIPMENT AND GOODWILL (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Capitalized exploratory well costs for continuing operations
Balance — beginning of year	$ 112	$ 108	$ 56
Exploratory well costs acquired through the Acquisition	231	0	0
Additions to capitalized exploratory well costs pending the determination of proved reserves	383	220	201
Reclassifications to property, plant and equipment based on the determination of proved reserves	(230)	(198)	(128)
Capitalized exploratory well costs charged to expense	(72)	(18)	(21)
Balance — end of year	424	112	$ 108
Net capitalized costs attributable to unproved properties	29,500	$ 1,000
Goodwill derecognized	4,600
Anadarko Petroleum Corporation
Capitalized exploratory well costs for continuing operations
Goodwill recognized associated with the Acquisition	$ 5,800
Chemical | Low end of range
Capitalized exploratory well costs for continuing operations
The estimated useful lives of Occidental's chemical assets	3 years
Chemical | High end of range
Capitalized exploratory well costs for continuing operations
The estimated useful lives of Occidental's chemical assets	50 years
Marketing and Midstream
Capitalized exploratory well costs for continuing operations
Goodwill	$ 1,200

XML

THE ACQUISITION - NARRATIVE (Details) - USD ($)		5 Months Ended	12 Months Ended
	Aug. 08, 2019	Dec. 31, 2019	Dec. 31, 2019	Aug. 07, 2019
WES
Business Acquisition [Line Items]
Limited partner interest			55.40%
WES | WES | Public Ownership
Business Acquisition [Line Items]
Limited partner interest			44.60%
Revolving Credit Facility
Business Acquisition [Line Items]
Revolving credit facility, maximum borrowing capacity				$ 3,000,000,000.0
Anadarko Petroleum Corporation
Business Acquisition [Line Items]
Cash of acquirer in exchange for acquiree (usd per share)	$ 59.00
Exchange ratio (per share of Anadarko common stock)	0.2934
Closing price per share, common stock (usd per share)	$ 46.31
Debt instrument issued	$ 21,800,000,000
Amount from exercise of warrants	10,000,000,000
Assumed debt	13,240,000,000
Property, plant and equipment	49,074,000,000
Revenues from date of merger		$ 4,200,000,000
Net loss attributable to common shareholders from date of merger		1,700,000,000
Anadarko Petroleum Corporation | Proved gas and oil properties
Business Acquisition [Line Items]
Property, plant and equipment	19,100,000,000
Anadarko Petroleum Corporation | Unproved Properties
Business Acquisition [Line Items]
Property, plant and equipment	27,400,000,000
Anadarko Petroleum Corporation | Land, Mineral Interests And Corporate Properties
Business Acquisition [Line Items]
Property, plant and equipment	$ 2,500,000,000
Anadarko Petroleum Corporation | Customer Relationships
Business Acquisition [Line Items]
Amortization period	30 years
Anadarko Petroleum Corporation | Level 2
Business Acquisition [Line Items]
Assumed debt	$ 2,500,000,000
Anadarko Petroleum Corporation | WES
Business Acquisition [Line Items]
Assumed debt	7,407,000,000
Property, plant and equipment	10,160,000,000
Anadarko Petroleum Corporation | WES | Level 2
Business Acquisition [Line Items]
Assumed debt	730,000,000
Anadarko Petroleum Corporation | WES
Business Acquisition [Line Items]
Revenues from date of merger		$ 1,100,000,000
Anadarko Petroleum Corporation | Revolving Credit Facility
Business Acquisition [Line Items]
Revolving credit facility, additional commitment	$ 2,000,000,000.0
Anadarko Petroleum Corporation | Series A Preferred Stock
Business Acquisition [Line Items]
Shares issued (in shares)	100,000
Anadarko Petroleum Corporation | Common Stock
Business Acquisition [Line Items]
Closing price per share, common stock (usd per share)	$ 46.31
Shares issued (in shares)	144,000,000
Number of securities called by warrant (in shares)	80,000,000
Exercise price of warrant (usd per share)	$ 62.50
Anadarko Petroleum Corporation | Senior notes
Business Acquisition [Line Items]
Debt instrument issued	$ 13,000,000,000.0
Anadarko Petroleum Corporation | Secured Debt
Business Acquisition [Line Items]
Debt instrument issued	$ 8,800,000,000

XML

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Values - Nonrecurring
Pre-tax impairment and related charges on domestic undeveloped leases	$ 285
Impairments of assets	285
Qatar ISSD
Fair Values - Nonrecurring
Pre-tax impairment charges	39
Impairments of assets	39
Qatar ISND and ISSD
Fair Values - Nonrecurring
Impairments of assets		$ 416
Proved and unproved non-core Permian acreages
Fair Values - Nonrecurring
Pre-tax impairment charges			$ 397
WES
Fair Values - Nonrecurring
Charge recorded as a result of loss of control	1,000
Recurring | Accrued liabilities
Liabilities:
Netting and Collateral	0	0
Recurring | Deferred credits and other liabilities - other
Liabilities:
Netting and Collateral	0	0
Recurring | Level 1 | Accrued liabilities
Liabilities:
Embedded derivative	0	0
Recurring | Level 1 | Deferred credits and other liabilities - other
Liabilities:
Embedded derivative	0	0
Recurring | Level 2 | Accrued liabilities
Liabilities:
Embedded derivative	40	66
Recurring | Level 2 | Deferred credits and other liabilities - other
Liabilities:
Embedded derivative	49	116
Recurring | Level 3 | Accrued liabilities
Liabilities:
Embedded derivative	0	0
Recurring | Level 3 | Deferred credits and other liabilities - other
Liabilities:
Embedded derivative	0	$ 0
Non recurring | Risk-Adjusted Discount Rate
Fair Values - Nonrecurring
Measurement input		10.00%
Fair Value | Recurring | Accrued liabilities
Liabilities:
Embedded derivative	40	$ 66
Fair Value | Recurring | Deferred credits and other liabilities - other
Liabilities:
Embedded derivative	$ 49	$ 116

XML

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of domestic and foreign components of income (loss) from continuing operations before domestic and foreign income taxes

The following summarizes domestic and foreign components of income (loss) from continuing operations before domestic and foreign income taxes for the years ended December 31:

millions	2019			2018		2017
Domestic	$	(1,632	)	$	3,431	$	(609	)
Foreign	1,818			2,177		1,937
Total	$	186		$	5,608	$	1,328

Schedule of provisions (credits) for domestic and foreign income taxes on continuing operations

The following summarizes components of income tax expense (benefit) on continuing operations for the years ended December 31:

millions	2019			2018			2017
Current
Federal	$	33		$	(23	)	$	(81	)
State and Local	46			52			11
Foreign	1,641			1,077			806
Total current tax expense	$	1,720		$	1,106		$	736
Deferred
Federal	(130		)	422			(856		)
State and Local	17			12			23
Foreign	(914		)	(63		)	114
Total deferred tax expense (benefit)	$	(1,027	)	$	371		$	(719	)
Total income tax expense	$	693		$	1,477		$	17

Schedule of reconciliation of the United States federal statutory income tax rate to Occidental's worldwide effective tax rate on income from continuing operations stated as a percentage of pre-tax income

The following reconciliation of the U.S federal statutory income tax rate to Occidental’s worldwide effective tax rate on income from continuing operations for the years ended December 31 is stated as a percentage of income (loss) from continuing operations before income taxes:

	2019		2018		2017
U.S. federal statutory tax rate	21	%	21	%	35	%
Enhanced oil recovery credit and other general business credits	(4	)	(3	)	(9	)
Change in federal income tax rate	—		—		(44	)
Tax (benefit) expense due to reversal of indefinite reinvestment assertion	—		(2	)	7
Tax impact from foreign operations	187		11		12
State income taxes, net of federal benefit	28		1		2
Uncertain tax positions	13		—		—
Transaction costs	19		—		—
Non-controlling interest	(16	)	—		—
Executive compensation limitation	24		—		—
Stock warrants	(9	)	—		—
WES loss of control	113		—		—
Other	(3	)	(2	)	(2	)
Worldwide effective tax rate	373	%	26	%	1	%

Schedule of tax effects of temporary differences resulting in deferred income taxes

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2019, and 2018 were as follows:

millions	2019			2018
Deferred tax liabilities
Property, plant and equipment differences	$	(12,375	)	$	(2,089	)
Equity investments, partnerships and foreign subsidiaries	(989		)	(161		)
Gross long-term deferred tax liabilities	(13,364		)	(2,250		)
Deferred tax assets
Environmental reserves	261			195
Postretirement benefit accruals	441			176
Deferred compensation and benefits	266			170
Asset retirement obligations	906			280
Foreign tax credit carryforwards	4,379			2,356
General business credit carryforwards	443			429
Net operating loss carryforward	692			29
Interest expense carryforward	492			—
All other	782			111
Gross long-term deferred tax assets	8,662			3,746
Valuation allowance	(4,959		)	(2,403		)
Net long-term deferred tax assets	$	3,703		$	1,343
Less: Foreign deferred tax asset in long-term receivables and other assets, net	$	(56	)	$	—
Total deferred income taxes, net	$	(9,717	)	$	(907	)

Schedule of reconciliation of the beginning and ending amount of unrecognized tax benefits

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

millions	2019		2018			2017
Balance at January 1	$	—	$	22		$	22
Increase related to Anadarko Acquisition	2,143		—			—
Increases related to current-year positions	30		—			—
Settlements	—		(22		)	—
Balance at December 31	$	2,173	$	—		$	22

XML

THE ACQUISITION (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Schedule of Purchase Consideration

The following table presents the Acquisition consideration paid to Anadarko stockholders as a result of the Acquisition:

millions except per-share amounts	As of August 8, 2019
Total shares of Anadarko common stock eligible for Acquisition consideration		491.6
Cash consideration (per share of common stock and shares underlying Anadarko stock-based awards eligible for Acquisition consideration)		$	59.00
Cash portion of Acquisition consideration		$	29,002
Total shares of Anadarko common stock eligible for Acquisition consideration		491.6
Exchange ratio (per share of Anadarko common stock)		0.2934
Total shares of Occidental common stock issued to Anadarko stockholders		144
Average share price of Occidental common stock at August 8, 2019		$	46.31
Stock portion of Acquisition consideration		$	6,679
Acquisition consideration attributable to Anadarko stock-based awards		$	23
Total Acquisition consideration		$	35,704

Schedule of Preliminary Purchase Price Allocation

The following table sets forth the preliminary allocation of the Acquisition consideration. Certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, final appraisals of certain assets acquired and liabilities assumed, valuation of pre-Acquisition contingencies and final tax returns that provide underlying tax basis of assets acquired and liabilities assumed. Occidental will finalize the purchase price allocation during the 12-month period following the Acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

millions	As of August 8, 2019
Fair value of assets acquired:
Current assets		$	3,596
Africa Assets held for sale		10,616
Investments in unconsolidated entities		194
Property, plant and equipment		49,074
Other assets		836
Amount attributable to assets acquired		$	64,316
Fair value of liabilities assumed:
Current liabilities		$	3,410
Liabilities of Africa Assets held for sale		2,200
Long-term debt		13,240
Deferred income taxes		8,607
Asset retirement obligations		2,724
Pension and post-retirement obligations		1,072
Non-current derivative liabilities		1,280
Other long-term liabilities		2,323
Amount attributable to liabilities assumed		$	34,856
Net assets		$	29,460
Fair value of WES net assets acquired less noncontrolling interests (a)		$	6,244
Total Acquisition consideration		$	35,704

^(a)  See Note 1 - Summary of Significant Accounting Policies for a discussion of the WES investment.

The following table summarizes the fair value of the major categories of WES assets acquired and liabilities assumed at the Acquisition date as well as the noncontrolling interest, which primarily consists of the 44.6% limited partner interest in WES owned by the public. The fair value of Occidental’s controlling interest in WES is calculated based on the market capitalization value at the Acquisition date.

millions	As of August 8, 2019
Fair value of WES assets acquired:
Current assets		$	499
Investments in unconsolidated entities		2,425
Property, plant and equipment		10,160
Intangible assets - customer relationships		1,800
Goodwill		5,772
Other assets		342
Amount attributable to assets acquired		$	20,998
Fair value of WES liabilities assumed:
Current liabilities		$	815
Long-term debt		7,407
Deferred income taxes		1,174
Asset retirement obligations		321
Other long-term liabilities		142
Amount attributable to liabilities assumed		$	9,859
Net assets		$	11,139
Less: Fair value of noncontrolling interests in WES		$	4,895
Fair value of WES net assets acquired less noncontrolling interests		$	6,244

Pro Forma Information

The following table summarizes the unaudited pro forma condensed financial information of Occidental as if the Acquisition had occurred on January 1, 2018:

	Year ended December 31,
millions except per-share amounts	2019			2018
Revenues	$	28,723		$	31,206
Net income (loss) attributable to common stockholders (a)	$	(769	)	$	2,965
Net income (loss) attributable to common stockholders per share—basic	$	(0.95	)	$	3.26
Net income (loss) attributable to common stockholders per share—diluted	$	(0.95	)	$	3.25

^(a) 

Excluding the pro-forma results of WES, net income (loss) attributable to common stockholders would be $(1.1) billion and $2.8 billion for the years ended December 31, 2019 and 2018, respectively.

Schedule of Merger-Related Costs

The following table summarizes the Acquisition-related costs incurred for the year ended December 31:

millions	2019
Employee severance and related employee cost	$	1,033
Licensing fees for critical seismic data	401
Bank, legal, consulting and other	213
Total	$	1,647

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Long-term debt

Long-term debt consisted of the following:

millions	December 31, 2019
4.850% senior notes due 2021		$	677
2.600% senior notes due 2021		1,500
4.100% senior notes due 2021		1,249
Variable rate bonds due 2021 (2.854% as of December 31, 2019)		500
Variable rate bonds due 2021 (3.151% as of December 31, 2019)		500
2-year variable rate Term Loan due 2021 (3.111% as of December 31, 2019)		1,956
2.700% senior notes due 2022		2,000
3.125% senior notes due 2022		814
2.600% senior notes due 2022		400
Variable rate bonds due 2022 (3.360% as of December 31, 2019)		1,500
2.700% senior notes due 2023		1,191
8.750% medium-term notes due 2023		22
2.900% senior notes due 2024		3,000
6.950% senior notes due 2024		650
3.450% senior notes due 2024		248
3.500% senior notes due 2025		750
5.550% senior notes due 2026		1,100
3.200% senior notes due 2026		1,000
3.400% senior notes due 2026		1,150
7.500% debentures due 2026		112
3.000% senior notes due 2027		750
7.125% debentures due 2027		150
7.000% debentures due 2027		48
6.625% debentures due 2028		14
7.150% debentures due 2028		235
7.200% senior debentures due 2028		82
7.200% debentures due 2029		135
7.950% debentures due 2029		116
8.450% senior debentures due 2029		116
3.500% senior notes due 2029		1,500
Variable rate bonds due 2030 (1.705% as of December 31, 2019)		68
7.500% senior notes due 2031		900
7.875% senior notes due 2031		500
6.450% senior notes due 2036		1,750
Zero Coupon senior notes due 2036		2,271
6.500% note payable to WES due 2038		260
4.300% senior notes due 2039		750
7.950% senior notes due 2039		325
6.200% senior notes due 2040		750
4.500% senior notes due 2044		625
4.625% senior notes due 2045		750
6.600% senior notes due 2046		1,100
4.400% senior notes due 2046		1,200
4.100% senior notes due 2047		750
4.200% senior notes due 2048		1,000
4.400% senior notes due 2049		750
7.730% debentures due 2096		60
7.500% debentures due 2096		78
7.250% debentures due 2096		49
Total borrowings at face value(a)		37,401
Adjustments to book value:
Unamortized premium, net		914
Debt issuance costs		(125		)
Long-term finance leases		347
Long-term Debt, net		$	38,537

^(a)  Total borrowings at face value included a $310 thousand 7.25% senior note due 2025.

millions	December 31, 2018
Occidental
9.250% senior debentures due 2019		$	116
4.100% senior notes due 2021		1,249
3.125% senior notes due 2022		813
2.600% senior notes due 2022		400
2.700% senior notes due 2023		1,191
8.750% medium-term notes due 2023		22
3.500% senior notes due 2025		750
3.400% senior notes due 2026		1,150
3.000% senior notes due 2027		750
7.200% senior debentures due 2028		82
8.450% senior debentures due 2029		116
4.625% senior notes due 2045		750
4.400% senior notes due 2046		1,200
4.100% senior notes due 2047		750
4.200% senior notes due 2048		1,000
Variable rate bonds due 2030 (1.9% as of December 31, 2018)		68
Total borrowings at face value		10,407
Adjustments to book value:
Unamortized discount, net		(36		)
Debt issuance costs		(54		)
Current maturities		(116		)
Long-term Debt, net		$	10,201

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

LONG-TERM DEBT

NOTE 7 - LONG-TERM DEBT

Long-term debt consisted of the following:

millions	December 31, 2019
4.850% senior notes due 2021		$	677
2.600% senior notes due 2021		1,500
4.100% senior notes due 2021		1,249
Variable rate bonds due 2021 (2.854% as of December 31, 2019)		500
Variable rate bonds due 2021 (3.151% as of December 31, 2019)		500
2-year variable rate Term Loan due 2021 (3.111% as of December 31, 2019)		1,956
2.700% senior notes due 2022		2,000
3.125% senior notes due 2022		814
2.600% senior notes due 2022		400
Variable rate bonds due 2022 (3.360% as of December 31, 2019)		1,500
2.700% senior notes due 2023		1,191
8.750% medium-term notes due 2023		22
2.900% senior notes due 2024		3,000
6.950% senior notes due 2024		650
3.450% senior notes due 2024		248
3.500% senior notes due 2025		750
5.550% senior notes due 2026		1,100
3.200% senior notes due 2026		1,000
3.400% senior notes due 2026		1,150
7.500% debentures due 2026		112
3.000% senior notes due 2027		750
7.125% debentures due 2027		150
7.000% debentures due 2027		48
6.625% debentures due 2028		14
7.150% debentures due 2028		235
7.200% senior debentures due 2028		82
7.200% debentures due 2029		135
7.950% debentures due 2029		116
8.450% senior debentures due 2029		116
3.500% senior notes due 2029		1,500
Variable rate bonds due 2030 (1.705% as of December 31, 2019)		68
7.500% senior notes due 2031		900
7.875% senior notes due 2031		500
6.450% senior notes due 2036		1,750
Zero Coupon senior notes due 2036		2,271
6.500% note payable to WES due 2038		260
4.300% senior notes due 2039		750
7.950% senior notes due 2039		325
6.200% senior notes due 2040		750
4.500% senior notes due 2044		625
4.625% senior notes due 2045		750
6.600% senior notes due 2046		1,100
4.400% senior notes due 2046		1,200
4.100% senior notes due 2047		750
4.200% senior notes due 2048		1,000
4.400% senior notes due 2049		750
7.730% debentures due 2096		60
7.500% debentures due 2096		78
7.250% debentures due 2096		49
Total borrowings at face value(a)		37,401
Adjustments to book value:
Unamortized premium, net		914
Debt issuance costs		(125		)
Long-term finance leases		347
Long-term Debt, net		$	38,537

^(a)  Total borrowings at face value included a $310 thousand 7.25% senior note due 2025.

millions	December 31, 2018
Occidental
9.250% senior debentures due 2019		$	116
4.100% senior notes due 2021		1,249
3.125% senior notes due 2022		813
2.600% senior notes due 2022		400
2.700% senior notes due 2023		1,191
8.750% medium-term notes due 2023		22
3.500% senior notes due 2025		750
3.400% senior notes due 2026		1,150
3.000% senior notes due 2027		750
7.200% senior debentures due 2028		82
8.450% senior debentures due 2029		116
4.625% senior notes due 2045		750
4.400% senior notes due 2046		1,200
4.100% senior notes due 2047		750
4.200% senior notes due 2048		1,000
Variable rate bonds due 2030 (1.9% as of December 31, 2018)		68
Total borrowings at face value		10,407
Adjustments to book value:
Unamortized discount, net		(36		)
Debt issuance costs		(54		)
Current maturities		(116		)
Long-term Debt, net		$	10,201

DEBT ISSUED AND ASSUMED

On August 8, 2019, Occidental issued $13.0 billion of new senior unsecured notes, consisting of both floating and fixed rate debt. Occidental also borrowed under the Term Loans, which consist of: (1) a 364-day senior unsecured variable-rate term loan tranche of $4.4 billion and (2) a two-year senior unsecured variable-rate term loan tranche of $4.4 billion. In total, the $21.8 billion in debt issued was used to finance part of the cash portion of the purchase price for the Acquisition.

In the Acquisition, Occidental assumed Anadarko debt with an outstanding principal balance of $11.9 billion. In September 2019, Occidental completed its offers to exchange the Anadarko senior notes and debentures assumed as part of the Acquisition for notes of a corresponding series issued by Occidental and cash, and related solicitation of consents. Of the approximately $11.9 billion in aggregate principal amount of Anadarko senior notes and debentures offered in the exchange, 97%, or approximately $11.5 billion, were tendered and accepted in the exchange offers. The portion not exchanged, approximately $400 million, remains outstanding with the original terms.

DEBT REPAYMENT

In 2019, Occidental paid approximately $7.0 billion of long-term debt including a majority of the Term Loans using proceeds from assets sales and available cash.

REVOLVING CREDIT FACILITY

On June 3, 2019, Occidental entered into an amendment to its existing $3.0 billion revolving credit facility (Occidental RCF) pursuant to which, among other things, the commitments under the Occidental RCF were increased to $5.0 billion at the closing of the Acquisition. Borrowings under the Occidental RCF bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental’s senior debt ratings. The facility has similar terms to other debt agreements and does 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 repayment. The facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. Occidental has not drawn down any amounts under the Occidental RCF. In 2019, Occidental paid average annual facility fees of 0.11% on the total commitment amount.

ZERO COUPON NOTES DUE 2036

The Zero Coupon senior notes due 2036 (Zero Coupons) have an aggregate principal amount due at maturity of approximately $2.3 billion, reflecting an accretion rate of 5.24%. The Zero Coupons can be put to Occidental in October of each year, in whole or in part, for the then-accreted value of the outstanding Zero Coupons. The Zero Coupons can next be put to Occidental in October 2020, which, if put in whole, would be $992 million at such date. Occidental has the ability and intent to refinance these obligations using long-term debt should a put be exercised.

DEBT GUARANTEES

As of December 31, 2019, and 2018, Occidental had provided limited recourse guarantees on approximately $242 million and $244 million, respectively, of Dolphin Energy’s debt, which are limited to certain political and other events.

FAIR VALUE OF DEBT

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, 2019, and 2018, substantially all of which were classified as Level 1, were approximately $38.8 billion and $10.3 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, 2019, and 2018, variable-rate debt constituted approximately 12% and 1% of Occidental’s total debt, respectively.

DEBT MATURITIES

At December 31, 2019, future principal payments on long-term debt aggregated approximately $37.4 billion, of which, $6.4 billion is due in 2021, $4.7 billion is due in 2022, $1.2 billion is due in 2023, and $25.1 billion is due in 2024 and thereafter.

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THE ACQUISITION

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

THE ACQUISITION

NOTE 3 - THE ACQUISITION

On May 9, 2019, Occidental entered into the Acquisition Agreement with Anadarko. On August 8, 2019, Anadarko’s stockholders voted to approve the Acquisition and it was made effective the same day. The Acquisition added to Occidental’s oil and gas portfolio, primarily in the Permian Basin, DJ Basin and Gulf of Mexico, and a controlling interest in WES.

In exchange for each share of Anadarko common stock, Anadarko stockholders received $59.00 in cash and 0.2934 of a share of Occidental common stock, plus cash in lieu of any fractional share of Occidental common stock that otherwise would have been issued, based on the average price of $46.31 per share of Occidental common stock on the NYSE on August 8, 2019.

In connection with the Acquisition, Occidental issued $13.0 billion of new senior unsecured notes, $8.8 billion of term loans (the Term Loans) and 100,000 shares of series A preferred stock (the Preferred Stock) with a warrant to purchase 80 million shares of Occidental common stock at an exercise price of $62.50 (the Warrant) for $10 billion. In addition, Occidental increased its existing $3.0 billion revolving credit facility by an additional $2.0 billion in commitments. See Note 7 - Long-term Debt and Note 13 - Stockholders’ Equity for additional information.

The Acquisition constitutes a business combination and was accounted for using the acquisition method of accounting. The following table presents the Acquisition consideration paid to Anadarko stockholders as a result of the Acquisition:

millions except per-share amounts	As of August 8, 2019
Total shares of Anadarko common stock eligible for Acquisition consideration		491.6
Cash consideration (per share of common stock and shares underlying Anadarko stock-based awards eligible for Acquisition consideration)		$	59.00
Cash portion of Acquisition consideration		$	29,002
Total shares of Anadarko common stock eligible for Acquisition consideration		491.6
Exchange ratio (per share of Anadarko common stock)		0.2934
Total shares of Occidental common stock issued to Anadarko stockholders		144
Average share price of Occidental common stock at August 8, 2019		$	46.31
Stock portion of Acquisition consideration		$	6,679
Acquisition consideration attributable to Anadarko stock-based awards		$	23
Total Acquisition consideration		$	35,704

The following table sets forth the preliminary allocation of the Acquisition consideration. Certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, final appraisals of certain assets acquired and liabilities assumed, valuation of pre-Acquisition contingencies and final tax returns that provide underlying tax basis of assets acquired and liabilities assumed. Occidental will finalize the purchase price allocation during the 12-month period following the Acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

millions	As of August 8, 2019
Fair value of assets acquired:
Current assets		$	3,596
Africa Assets held for sale		10,616
Investments in unconsolidated entities		194
Property, plant and equipment		49,074
Other assets		836
Amount attributable to assets acquired		$	64,316
Fair value of liabilities assumed:
Current liabilities		$	3,410
Liabilities of Africa Assets held for sale		2,200
Long-term debt		13,240
Deferred income taxes		8,607
Asset retirement obligations		2,724
Pension and post-retirement obligations		1,072
Non-current derivative liabilities		1,280
Other long-term liabilities		2,323
Amount attributable to liabilities assumed		$	34,856
Net assets		$	29,460
Fair value of WES net assets acquired less noncontrolling interests (a)		$	6,244
Total Acquisition consideration		$	35,704

^(a)  See Note 1 - Summary of Significant Accounting Policies for a discussion of the WES investment.

The following table summarizes the fair value of the major categories of WES assets acquired and liabilities assumed at the Acquisition date as well as the noncontrolling interest, which primarily consists of the 44.6% limited partner interest in WES owned by the public. The fair value of Occidental’s controlling interest in WES is calculated based on the market capitalization value at the Acquisition date.

millions	As of August 8, 2019
Fair value of WES assets acquired:
Current assets		$	499
Investments in unconsolidated entities		2,425
Property, plant and equipment		10,160
Intangible assets - customer relationships		1,800
Goodwill		5,772
Other assets		342
Amount attributable to assets acquired		$	20,998
Fair value of WES liabilities assumed:
Current liabilities		$	815
Long-term debt		7,407
Deferred income taxes		1,174
Asset retirement obligations		321
Other long-term liabilities		142
Amount attributable to liabilities assumed		$	9,859
Net assets		$	11,139
Less: Fair value of noncontrolling interests in WES		$	4,895
Fair value of WES net assets acquired less noncontrolling interests		$	6,244

The aggregate purchase price noted above was allocated to the major categories of assets and liabilities acquired based upon their preliminary estimated fair values at the date of the Acquisition. The valuation of certain assets, including property and intangible assets, are based on preliminary appraisals. The majority of measurements of assets acquired and liabilities assumed, other than debt, are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties and equipment is based on both available market data and a cost approach.

Onshore undeveloped oil and gas properties were valued primarily using a market approach based on comparable transactions for similar properties while the income approach was utilized for developed oil and gas properties based on underlying reserve projections at the Acquisition date. For the acquired Gulf of Mexico offshore properties, an income approach was used as the primary valuation method based on underlying reserve projections. Income approaches are considered level 3 fair value estimates and include significant assumptions of future production, commodity prices, and operating and capital cost estimates, discounted using weighted average cost of capital for industry peers, and risk adjustment factors based on reserve category. Price assumptions were based on a combination of market information and published industry resources adjusted for historical differentials. Cost estimates were based on current observable costs inflated based on historical and expected future inflation. Taxes were based on current statutory rates.

The fair value of WES investments in unconsolidated entities were valued using an income approach for each investment, with significant inputs being forecasted distributions, an anticipated growth rate and an estimated discount rate. Acquired WES property, plant and equipment primarily consisted of gathering systems and processing and treating facilities and were primarily valued using a replacement cost approach. Intangible assets primarily consist of relationships with third-party customers, the fair value of which was determined using an income approach, including significant assumptions related to estimated cash flows from third-party customers less a contributory asset charge, a customer retention rate and an estimated discount rate. Customer relationships are amortized over 30 years. Goodwill is attributable to the difference in WES market capitalization value and the net assets acquired and primarily relates to the relationship between Occidental and WES that is not recognized as a separate asset, due to Occidental consolidating WES as of the Acquisition date.

Deferred income taxes represent the tax effects of differences in the tax basis and acquisition-date fair values of assets acquired and liabilities assumed. The measurement of debt instruments was based on unadjusted quoted prices in an active market and are primarily Level 1; approximately $2.5 billion of the assumed Anadarko debt is considered Level 2, while approximately $730 million of the WES debt is considered Level 2. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2.

With the completion of the Acquisition, Occidental acquired proved and unproved properties of approximately $19.1 billion and $27.4 billion, respectively, primarily associated with the Permian Basin, DJ Basin, Gulf of Mexico and Powder River Basin. The remaining $2.5 billion in PP&E which consists of non-oil and gas mineral interests and other real estate assets.

From the date of the Acquisition through December 31, 2019, revenues and the net loss attributable to common stockholders associated with the operations acquired through the Acquisition totaled $4.2 billion and $1.7 billion, respectively, which includes a charge as a result of recording Occidental’s investment in WES at fair value as of December 31, 2019 upon the loss of control.

The following table summarizes the unaudited pro forma condensed financial information of Occidental as if the Acquisition had occurred on January 1, 2018:

	Year ended December 31,
millions except per-share amounts	2019			2018
Revenues	$	28,723		$	31,206
Net income (loss) attributable to common stockholders (a)	$	(769	)	$	2,965
Net income (loss) attributable to common stockholders per share—basic	$	(0.95	)	$	3.26
Net income (loss) attributable to common stockholders per share—diluted	$	(0.95	)	$	3.25

^(a)  Excluding the pro-forma results of WES, net income (loss) attributable to common stockholders would be $(1.1) billion and $2.8 billion for the years ended December 31, 2019 and 2018, respectively.

The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Acquisition been completed at January 1, 2018, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma information for 2019 and 2018 is a result of combining the statements of operations of Occidental with the pre-Acquisition results from January 1, 2019, and 2018 of Anadarko and included adjustments for revenues and direct expenses. The pro forma results exclude results from the Africa Assets, any cost savings anticipated as a result of the Acquisition and the impact of any Acquisition-related costs. The pro forma results include adjustments to DD&A (depreciation, depletion and amortization) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest expense. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the Acquisition are properly reflected.

ANADARKO ACQUISITION-RELATED COSTS

The following table summarizes the Acquisition-related costs incurred for the year ended December 31:

millions	2019
Employee severance and related employee cost	$	1,033
Licensing fees for critical seismic data	401
Bank, legal, consulting and other	213
Total	$	1,647

Employee severance and related employee cost primarily relates to one-time severance costs and the accelerated vesting of certain Anadarko share-based awards for former Anadarko employees based on the terms of the Acquisition Agreement and existing change of control provisions within the former Anadarko employment agreements. In addition, employee severance and related employee cost included expenses for a voluntary separation program for eligible employees. Occidental initiated this program to align the size and composition of its workforce with its expected future operating and capital plans. Employee notifications related to the voluntary separation program were ongoing at December 31, 2019, with additional expenses associated with the program expected to be incurred through most of 2020. Employees may revoke their participation in the voluntary severance program up to their separation date.

The seismic licensing fees relate to relicensing of critical seismic data related to the Gulf of Mexico, Permian Basin and DJ Basin that Anadarko had licensed from third-party vendors. The third-party vendors who own the seismic data require a transfer fee in order for Occidental to use the data.

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Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 3,032	$ 3,033
Restricted cash and restricted cash equivalents	480	0
Trade receivables, net of reserves of $19 in 2019 and $21 in 2018	6,373	4,893
Inventories	1,447	1,260
Assets held for sale	6,026	0
Other current assets	1,323	746
Total current assets	18,681	9,932
INVESTMENTS
INVESTMENTS IN UNCONSOLIDATED ENTITIES	6,389	1,680
PROPERTY, PLANT AND EQUIPMENT
GROSS PROPERTY, PLANT AND EQUIPMENT	122,347	74,420
Accumulated depreciation, depletion and amortization	(41,878)	(42,983)
Property, plant and equipment, net	80,469	31,437
OPERATING LEASE ASSETS	1,385
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	2,406	805
TOTAL ASSETS	109,330	43,854
CURRENT LIABILITIES
Current maturities of long-term debt	51	116
Current operating lease liabilities	569
Accounts payable	7,017	4,885
Accrued liabilities	5,302	2,411
Liabilities of assets held for sale	2,010	0
Total current liabilities	14,949	7,412
Long-term debt, net	38,537	10,201
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes, net	9,717	907
Asset retirement obligations	4,385	1,424
Pension and postretirement obligations	1,807	809
Environmental remediation liabilities	1,035	762
Operating lease liabilities	854
Other	3,814	1,009
Total Deferred Credits and Other Liabilities	21,612	4,911
EQUITY
Preferred stock, at $1.00 per share par value (100,000 shares at December 31, 2019)	9,762	0
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, issued shares: 2019 — 1,044,434,893 and 2018 — 895,115,637	209	179
Treasury stock: 2019 — 150,323,151 shares and 2018 — 145,726,051 shares	(10,653)	(10,473)
Additional paid-in capital	14,955	8,046
Retained earnings	20,180	23,750
Accumulated other comprehensive loss	(221)	(172)
Total stockholders’ equity	34,232	21,330
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	109,330	43,854
Oil and Gas Segment
PROPERTY, PLANT AND EQUIPMENT
GROSS PROPERTY, PLANT AND EQUIPMENT	105,881	58,799
Chemical Segment
PROPERTY, PLANT AND EQUIPMENT
GROSS PROPERTY, PLANT AND EQUIPMENT	7,172	7,001
Midstream Segment
PROPERTY, PLANT AND EQUIPMENT
GROSS PROPERTY, PLANT AND EQUIPMENT	8,176	8,070
Corporate
PROPERTY, PLANT AND EQUIPMENT
GROSS PROPERTY, PLANT AND EQUIPMENT	$ 1,118	$ 550

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Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Unrealized losses on derivatives, tax	$ 36	$ 2	$ (7)
Pension and postretirement gains, tax	(25)	(38)	4
Reclassification to income of realized (gains)/losses on derivatives, net	$ 0	$ (4)	$ 0

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

NOTE 17 - FAIR 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 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:

millions	Fair Value Measurements Using								Total Fair Value
Balance Sheet Classification	Level 1		Level 2		Level 3		Netting
December 31, 2019
Embedded Derivatives
Accrued liabilities	$	—	$	40	$	—	$	—	$	40
Deferred credits and other liabilities - other	$	—	$	49	$	—	$	—	$	49
December 31, 2018
Embedded Derivatives
Accrued liabilities	$	—	$	66	$	—	$	—	$	66
Deferred credits and other liabilities - other	$	—	$	116	$	—	$	—	$	116

FAIR VALUES – NONRECURRING

During 2019, Occidental measured assets and liabilities at acquisition-date fair value on a nonrecurring basis related to the Acquisition. See Note 3 - The Acquisition for more detail.

In 2019, Occidental recorded a $1 billion charge as a result of recording Occidental’s equity investment in WES at fair value upon loss of control, see Note 1 - Summary of Significant Accounting Policies. Additionally, Occidental’s oil and gas segment recognized pre-tax impairment and related charges of $285 million related to domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and $39 million related to Occidental’s mutually agreed early termination of its Qatar ISSD contract.

During 2018, Occidental recognized pre-tax impairment and related charges of $416 million primarily related to Qatar ISND and ISSD proved properties and inventory. The fair value of the proved properties was measured based on the income approach, which 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, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk-adjusted discount rate of 10 percent. These inputs are categorized as Level 3 in the fair value hierarchy.

During 2017, Occidental recognized pre-tax impairment charges of $397 million primarily related to held for sale non-core proved and unproved Permian acreage. Assumptions for proved and unproved properties classified as held for sale include estimated third-party prices to be received based on recent transactions of similar acreage.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash, cash equivalents, restricted cash and restricted cash equivalents and other on-balance sheet financial instruments, other than fixed-rate debt, approximate fair value. See Note 7 - Long-term Debt for the fair value of Long-term debt.

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STOCKHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2019

Stockholders' Equity Note [Abstract]

STOCKHOLDERS' EQUITY

NOTE 13 - STOCKHOLDERS’ EQUITY

The following is a summary of common stock issuances:

Shares in thousands	Common Stock
Balance, December 31, 2016	892,215
Issued	1,252
Options exercised and other, net	2
Balance, December 31, 2017	893,469
Issued	1,628
Options exercised and other, net	19
Balance, December 31, 2018	895,116
Issued in the ordinary course	3,188
Issued as part of the Acquisition (a)	146,131
Balance, December 31, 2019	1,044,435

^(a)  Included approximately 2 million shares of common stock issued to a benefits trust for former Anadarko employees treated as treasury stock at December 31, 2019.

TREASURY STOCK

The total number of shares authorized for Occidental’s share repurchase program is 185 million shares of which 44.2 million may yet be purchased under the repurchase program. However, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time. In 2019, 2.7 million shares were purchased at an average price of $66.94 under the program and in 2018, 16.9 million shares were purchased at an average price of $74.92. No shares were purchased under the program in 2017. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year. As of December 31, 2019, 2018 and 2017, treasury stock shares numbered 150.3 million, 145.7 million, and 128.4 million, respectively.

PREFERRED STOCK

Occidental has authorized 50 million shares of preferred stock with a par value of $1.00 per share. On August 8, 2019, in connection with the Acquisition, Occidental issued 100,000 shares of series A preferred stock (the Preferred Stock), having a face value of $100,000 per share and a liquidation preference of $105,000 per share plus unpaid accrued dividends. In connection with the preferred stock issuance, Occidental also issued the Warrant. The holder of the Warrant and the Preferred Stock may redeem the Preferred Stock as payment for the exercise price of the Warrant in lieu of cash payment upon exercise. The Preferred Stock is redeemable at Occidental’s option after the 10th anniversary of issuance. Dividends on the Preferred Stock will accrue on the face value at a rate per annum of 8 percent, but will be paid only when, as, and if declared by Occidental’s Board of Directors. At any time, when such dividends have not been paid in full, the unpaid amounts will accrue dividends, compounded quarterly, at a rate per annum of 9 percent. Following the payment in full of any accrued but unpaid dividends, the dividend rate will remain at 9 percent per annum. In January 2020, Occidental paid $200 million in Preferred Stock dividends. At December 31, 2019, Occidental had 100,000 shares of preferred stock issued and outstanding, and none were outstanding in 2018 and 2017.

EARNINGS PER SHARE

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

millions except per share amounts	2019			2018			2017
Income (loss) from continuing operations	$	(507	)	$	4,131		$	1,311
Loss from discontinued operations	(15		)	—			—
Net income (loss)	$	(522	)	$	4,131		$	1,311
Less: Net income attributable to noncontrolling interest	(145		)	—			—
Less: Preferred stock dividends	(318		)	—			—
Net income (loss) attributable to common stock	$	(985	)	$	4,131		$	1,311
Less: Net income allocated to participating securities	—			(17		)	(6		)
Net income (loss), net of participating securities	$	(985	)	$	4,114		$	1,305
Weighted-average number of basic shares	809.5			761.7			765.1
Basic earnings (loss) per common share	$	(1.22	)	$	5.40		$	1.71
Net income (loss), net of participating securities	$	(985	)	$	4,114		$	1,305
Weighted-average number of basic shares	809.5			761.7			765.1
Dilutive securities	—			1.6			0.8
Total diluted weighted-average common shares	809.5			763.3			765.9
Diluted earnings (loss) per common share	$	(1.22	)	$	5.39		$	1.70

ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss consisted of the following after-tax amounts at December 31:

millions	2019			2018
Foreign currency translation adjustments	$	(7	)	$	(7	)
Unrealized gains (losses) on derivatives	(122		)	5
Pension and postretirement adjustments (a)	(92		)	(170		)
Total	$	(221	)	$	(172	)

^(a) 

See Note 15 - Retirement and Postretirement Benefit Plans for further information.

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2019

Investments And Related Party Transactions Disclosure [Abstract]

Schedule of significant equity investments

As of December 31, 2019, Occidental’s significant equity investments primarily consisted of the following:

millions	% Interest		Carrying amount
WES	56.3	%	$	5,128
OxyChem Ingleside Facility	50.0	%	679
Dolphin Energy Limited	24.5	%	240
Other	various		342
Total			$	6,389

Summarized financial information of equity-method investments

The following table presents the summarized financial information of its equity-method investments combined for the years ended and as of December 31:

millions	2019		2018		2017
Summarized Results of Operations(a)
Revenues and other income	$	26,520	$	28,091	$	13,843
Costs and expenses	24,084		25,029		12,230
Net income	$	2,436	$	3,062	$	1,613
Summarized Balance Sheet(b)
Current assets	$	1,130	$	5,587	$	5,754
Non-current assets	$	21,158	$	25,871	$	25,108
Current liabilities	$	785	$	4,879	$	4,479
Long-term debt	$	8,673	$	12,505	$	14,091
Other non-current liabilities	$	859	$	95	$	414
Stockholders’ equity	$	11,971	$	13,979	$	11,878

^(a)  The 2019 Summarized Results of Operations include results of Plains for the period beginning January 1, 2019 through the date Occidental’s interest was sold in September 2019.

^(b) 

The 2019 Summarized Balance Sheet included the balance of WES due to the loss of control on December 30, 2019 and excluded the balances of Plains as the interest was sold in September 2019.

Summary of related-party transactions

During 2019, 2018 and 2017, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties for the years ended December 31:

millions	2019		2018		2017
Sales (a,c)	$	691	$	805	$	636
Purchases (b,c)	$	463	$	502	$	387
Services	$	28	$	52	$	38
Advances and amounts due from related parties	$	133	$	63	$	63
Amounts due to related parties (d)	$	463	$	46	$	45

^(a)  In 2019, 2018 and 2017, sales of Occidental-produced oil and NGL to Plains Pipeline affiliates accounted for 87 percent, 89 percent and 86 percent of these totals, respectively. In September 2019, Occidental sold its remaining interest in Plains Pipeline.

^(b)  In 2019 and 2018, purchases of ethylene from the Ingleside ethylene cracker accounted for 98 percent of related-party purchases, respectively.

^(c)  Excluded sales to and purchases from WES as it was a consolidated subsidiary from the date of the Acquisition through December 31, 2019.

^(d) 

Amounts due to related parties at December 31, 2019 primarily consists of a 6.5% note payable to WES due 2038.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - RISKS AND UNCERTAINTIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
RISKS AND UNCERTAINTIES
Assets	$ 109,330	$ 43,854	$ 42,026
Net sales	18,674	$ 15,560
Outside North America
RISKS AND UNCERTAINTIES
Assets	14,900
Net sales	$ 4,600

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REVENUE - DISAGGREGATION OF REVENUE (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from customers	$ 18,674	$ 15,560
United States
Disaggregation of Revenue [Line Items]
Revenue from customers	15,327	11,086
Middle East
Disaggregation of Revenue [Line Items]
Revenue from customers	3,686	4,388
Latin America
Disaggregation of Revenue [Line Items]
Revenue from customers	858	936
Other International
Disaggregation of Revenue [Line Items]
Revenue from customers	67	80
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from customers	(1,264)	(930)
Intersegment Eliminations | United States
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Intersegment Eliminations | Middle East
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Intersegment Eliminations | Latin America
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Intersegment Eliminations | Other International
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment
Disaggregation of Revenue [Line Items]
Revenue from customers	13,530	10,441
Oil and Gas Segment | Oil
Disaggregation of Revenue [Line Items]
Revenue from customers	11,852	9,245
Oil and Gas Segment | NGL
Disaggregation of Revenue [Line Items]
Revenue from customers	921	691
Oil and Gas Segment | Gas
Disaggregation of Revenue [Line Items]
Revenue from customers	763	495
Oil and Gas Segment | Other
Disaggregation of Revenue [Line Items]
Revenue from customers	(6)	10
Oil and Gas Segment | United States
Disaggregation of Revenue [Line Items]
Revenue from customers	9,492	5,747
Oil and Gas Segment | United States | Oil
Disaggregation of Revenue [Line Items]
Revenue from customers	8,411	5,125
Oil and Gas Segment | United States | NGL
Disaggregation of Revenue [Line Items]
Revenue from customers	658	430
Oil and Gas Segment | United States | Gas
Disaggregation of Revenue [Line Items]
Revenue from customers	424	185
Oil and Gas Segment | United States | Other
Disaggregation of Revenue [Line Items]
Revenue from customers	(1)	7
Oil and Gas Segment | Middle East
Disaggregation of Revenue [Line Items]
Revenue from customers	3,335	3,963
Oil and Gas Segment | Middle East | Oil
Disaggregation of Revenue [Line Items]
Revenue from customers	2,758	3,405
Oil and Gas Segment | Middle East | NGL
Disaggregation of Revenue [Line Items]
Revenue from customers	263	261
Oil and Gas Segment | Middle East | Gas
Disaggregation of Revenue [Line Items]
Revenue from customers	319	294
Oil and Gas Segment | Middle East | Other
Disaggregation of Revenue [Line Items]
Revenue from customers	(5)	3
Oil and Gas Segment | Latin America
Disaggregation of Revenue [Line Items]
Revenue from customers	703	731
Oil and Gas Segment | Latin America | Oil
Disaggregation of Revenue [Line Items]
Revenue from customers	683	715
Oil and Gas Segment | Latin America | NGL
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Latin America | Gas
Disaggregation of Revenue [Line Items]
Revenue from customers	20	16
Oil and Gas Segment | Latin America | Other
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Other International
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Other International | Oil
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Other International | NGL
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Other International | Gas
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Other International | Other
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Intersegment Eliminations | Oil
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Intersegment Eliminations | NGL
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Intersegment Eliminations | Gas
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Oil and Gas Segment | Intersegment Eliminations | Other
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Chemical Segment
Disaggregation of Revenue [Line Items]
Revenue from customers	4,080	4,648
Chemical Segment | United States
Disaggregation of Revenue [Line Items]
Revenue from customers	3,858	4,363
Chemical Segment | Middle East
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Chemical Segment | Latin America
Disaggregation of Revenue [Line Items]
Revenue from customers	155	205
Chemical Segment | Other International
Disaggregation of Revenue [Line Items]
Revenue from customers	67	80
Chemical Segment | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment
Disaggregation of Revenue [Line Items]
Revenue from customers	2,328	1,401
Midstream Segment | Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from customers	746	982
Midstream Segment | Gas Processing | WES
Disaggregation of Revenue [Line Items]
Revenue from customers	1,110
Midstream Segment | Pipelines
Disaggregation of Revenue [Line Items]
Revenue from customers		311
Midstream Segment | Power and Other
Disaggregation of Revenue [Line Items]
Revenue from customers	472	108
Midstream Segment | United States
Disaggregation of Revenue [Line Items]
Revenue from customers	1,977	976
Midstream Segment | United States | Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from customers	395	557
Midstream Segment | United States | Gas Processing | WES
Disaggregation of Revenue [Line Items]
Revenue from customers	1,110
Midstream Segment | United States | Pipelines
Disaggregation of Revenue [Line Items]
Revenue from customers		311
Midstream Segment | United States | Power and Other
Disaggregation of Revenue [Line Items]
Revenue from customers	472	108
Midstream Segment | Middle East
Disaggregation of Revenue [Line Items]
Revenue from customers	351	425
Midstream Segment | Middle East | Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from customers	351	425
Midstream Segment | Middle East | Gas Processing | WES
Disaggregation of Revenue [Line Items]
Revenue from customers	0
Midstream Segment | Middle East | Pipelines
Disaggregation of Revenue [Line Items]
Revenue from customers		0
Midstream Segment | Middle East | Power and Other
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Latin America
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Latin America | Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Latin America | Gas Processing | WES
Disaggregation of Revenue [Line Items]
Revenue from customers	0
Midstream Segment | Latin America | Pipelines
Disaggregation of Revenue [Line Items]
Revenue from customers		0
Midstream Segment | Latin America | Power and Other
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Other International
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Other International | Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Other International | Gas Processing | WES
Disaggregation of Revenue [Line Items]
Revenue from customers	0
Midstream Segment | Other International | Pipelines
Disaggregation of Revenue [Line Items]
Revenue from customers		0
Midstream Segment | Other International | Power and Other
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Intersegment Eliminations | Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from customers	0	0
Midstream Segment | Intersegment Eliminations | Gas Processing | WES
Disaggregation of Revenue [Line Items]
Revenue from customers	0
Midstream Segment | Intersegment Eliminations | Pipelines
Disaggregation of Revenue [Line Items]
Revenue from customers		0
Midstream Segment | Intersegment Eliminations | Power and Other
Disaggregation of Revenue [Line Items]
Revenue from customers	$ 0	$ 0

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS - COMPONENTS OF NET PERIODIC BENEFIT COST (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Net periodic benefit costs:
Service cost — benefits earned during the period	$ 45	$ 5	$ 6
Interest cost on projected benefit obligation	39	15	17
Expected return on plan assets	(50)	(25)	(24)
Recognized actuarial loss	9	7	10
Recognized prior service credit	0	0	0
Liability (gain) loss due to curtailment	(91)	0	0
Special termination benefits	49	0	0
Other costs and adjustments	(2)	1	3
Net periodic benefit cost	(1)	3	12
Amounts that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	3
Estimated prior service cost that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	0
Postretirement Benefits
Net periodic benefit costs:
Service cost — benefits earned during the period	24	23	21
Interest cost on projected benefit obligation	36	34	38
Expected return on plan assets	0	0	0
Recognized actuarial loss	8	14	14
Recognized prior service credit	(8)	0	0
Liability (gain) loss due to curtailment	6	0	0
Special termination benefits	0	0	0
Other costs and adjustments	0	(2)	1
Net periodic benefit cost	66	$ 69	$ 74
Amounts that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	12
Estimated prior service cost that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	$ (8)

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STOCKHOLDERS' EQUITY (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
	Aug. 08, 2019	Jan. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Common stock issuances
Balance at the beginning of the year (in shares)		1,044,435,000	895,116,000	893,469,000	892,215,000
Issued (in shares)			3,188,000	1,628,000	1,252,000
Options exercised and other, net (in shares)				19,000	2,000
Issued as part of the Acquisition (in shares)			146,131,000
Balance at the end of the year (in shares)			1,044,435,000	895,116,000	893,469,000
TREASURY STOCK
Share repurchase program, authorized shares			185,000,000
Share repurchase program, shares yet to be repurchased			44,200,000
Shares purchased under share repurchase program			2,700,000	16,900,000	0
Share repurchase program, average cost per share of shares repurchased during period (in dollars per share)			$ 66.94	$ 74.92
Treasury stock, shares (in shares)			150,323,151	145,726,051	128,400,000
NONREDEEMABLE PREFERRED STOCK
Preferred stock, authorized shares (in shares)			50,000,000
Preferred stock, par value (in dollars per share)			$ 1.00
Issued as part of the Acquisition (in shares)			146,131,000
Preferred stock, shares outstanding (in shares)			100,000	0	0
Preferred stock issued (in shares)			100,000
Basic earnings per common share
Income (loss) from continuing operations			$ (507)	$ 4,131	$ 1,311
Loss from discontinued operations, net of tax			(15)	0	0
NET INCOME (LOSS)			(522)	4,131	1,311
Less: Net income attributable to noncontrolling interest			(145)	0	0
Less: Preferred stock dividends			(318)	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS			(985)	4,131	1,311
Less: Net income allocated to participating securities			0	(17)	(6)
Net income (loss), net of participating securities			$ (985)	$ 4,114	$ 1,305
Weighted average number of basic shares (in shares)			809,500,000	761,700,000	765,100,000
Basic earnings (loss) per common share (in dollars per share)			$ (1.22)	$ 5.40	$ 1.71
Diluted EPS
Net income (loss), net of participating securities			$ (985)	$ 4,114	$ 1,305
Weighted average number of basic shares (in shares)			809,500,000	761,700,000	765,100,000
Dilutive securities (in shares)			0	1,600,000	800,000
Total diluted weighted average common shares (in shares)			809,500,000	763,300,000	765,900,000
Diluted earnings (loss) per common share (in dollars per share)			$ (1.22)	$ 5.39	$ 1.70
ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss			$ 34,232	$ 21,330	$ 20,572	$ 21,497
Subsequent Event
NONREDEEMABLE PREFERRED STOCK
Payments of Ordinary Dividends, Preferred Stock and Preference Stock		$ 200
Anadarko Petroleum Corporation | Series A Preferred Stock
Common stock issuances
Issued as part of the Acquisition (in shares)	100,000
NONREDEEMABLE PREFERRED STOCK
Issued as part of the Acquisition (in shares)	100,000
Liquidation preference (in dollars per share)	$ 105,000
Dividend rate	8.00%
Dividend rate for unpaid amounts	9.00%
Common Stock
ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss			$ 209	179	179	178
Common Stock | Anadarko Petroleum Corporation
Common stock issuances
Issued as part of the Acquisition (in shares)			2,000,000
NONREDEEMABLE PREFERRED STOCK
Issued as part of the Acquisition (in shares)			2,000,000
Foreign currency translation adjustments
ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss			$ (7)	(7)
Unrealized gains (losses) on derivatives
ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss			(122)	5
Pension and postretirement adjustments
ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss			(92)	(170)
Accumulated Other Comprehensive Loss
ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss			$ (221)	$ (172)	$ (258)	$ (266)

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS - SUMMARY OF REVENUE AND COSTS FROM DISCONTINUED OPERATIONS (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Costs and other deductions
Discontinued operations, net of tax		$ (15)	$ 0	$ 0
Anadarko's Africa Assets | Disposed of by sale
Revenues and other income
Net sales	$ 739
Costs and other deductions
Oil and gas lease operating expense	81
Transportation expense	14
Taxes other than on income	133
Fair value adjustment on assets held for sale	244
Other	53
Total costs and other deductions	525
Income before income taxes	214
Income tax expense	(229)
Discontinued operations, net of tax	$ (15)

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THE ACQUISITION - PRELIMINARY PURCHASE PRICE ALLOCATION (Details) - Anadarko Petroleum Corporation $ in Millions	Aug. 08, 2019 USD ($)
Fair value of assets acquired:
Current assets	$ 3,596
Africa Assets held for sale	10,616
Investments in unconsolidated entities	194
Property, plant and equipment	49,074
Other assets	836
Amount attributable to assets acquired	64,316
Fair value of liabilities assumed:
Current liabilities	3,410
Liabilities of Africa Assets held for sale	2,200
Long-term debt	13,240
Deferred income taxes	8,607
Asset retirement obligations	2,724
Pension and post-retirement obligations	1,072
Non-current derivative liabilities	1,280
Other long-term liabilities	2,323
Amount attributable to liabilities assumed	34,856
Net assets	29,460
Fair value of noncontrolling interests	6,244
Total Acquisition consideration	35,704
WES
Fair value of assets acquired:
Current assets	499
Investments in unconsolidated entities	2,425
Property, plant and equipment	10,160
Intangible assets - customer relationships	1,800
Goodwill	5,772
Other assets	342
Amount attributable to assets acquired	20,998
Fair value of liabilities assumed:
Current liabilities	815
Long-term debt	7,407
Deferred income taxes	1,174
Asset retirement obligations	321
Other long-term liabilities	142
Amount attributable to liabilities assumed	9,859
Net assets	11,139
Fair value of noncontrolling interests	4,895
Total Acquisition consideration	$ 6,244

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INCOME TAXES - EFFECTIVE TAX RATE RECONCILIATION (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
U.S. federal statutory tax rate	21.00%	21.00%	35.00%
Enhanced oil recovery credit and other general business credits	(4.00%)	(3.00%)	(9.00%)
Change in federal income tax rate	0.00%	0.00%	(44.00%)
Tax (benefit) expense due to reversal of indefinite reinvestment assertion	0.00%	(2.00%)	7.00%
Tax impact from foreign operations	187.00%	11.00%	12.00%
State income taxes, net of federal benefit	28.00%	1.00%	2.00%
Uncertain tax positions	13.00%	0.00%	0.00%
Transaction costs	19.00%	0.00%	0.00%
Non-controlling interest	(16.00%)	0.00%	0.00%
Executive compensation limitation	24.00%	0.00%	0.00%
Stock warrants	(9.00%)	0.00%	0.00%
WES loss of control	113.00%	0.00%	0.00%
Other	(3.00%)	(2.00%)	(2.00%)
Worldwide effective tax rate	373.00%	26.00%	1.00%

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid	$ 911	$ 383	$ 351
Capitalized interest	85	46	52
Continuing operations
SUPPLEMENTAL CASH FLOW INFORMATION
Foreign, state and federal income taxes paid for continuing operations	1,700	1,100	800
Tax refund	79	82	768
Production, property and other taxes paid	$ 725	$ 505	$ 375

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ACCRUED LIABILITIES-CURRENT (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
ACCRUED LIABILITIES-CURRENT
Accrued liabilities for accrued payroll, commissions and related expenses	$ 1,200	$ 428
Dividends payable	884	600
Derivative financial instruments, included in accrued liabilities - current	$ 641	$ 134

XML

DERIVATIVES - MARKETING DERIVATIVES (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019 Bcf	Dec. 31, 2019 MMBbls	Dec. 31, 2019 $ / MillionCubicFeet	Dec. 31, 2019 $ / Barrel	Dec. 31, 2018 Bcf	Dec. 31, 2018 MMBbls	Dec. 31, 2018 $ / MillionCubicFeet	Dec. 31, 2018 $ / Barrel
Marketing Derivatives
Outstanding commodity derivatives contracts not designated as hedging instruments
Derivative instrument settlement period (within)	3 months
Marketing Derivatives | Not designated as hedging instruments
Outstanding commodity derivatives contracts not designated as hedging instruments
Weighted average sales price (in dollars per share)				2.17	60.60			3.18	58.81
Crude Oil & NGLs | Long position
Outstanding commodity derivatives contracts not designated as hedging instruments
Commodity contracts Volume (MMBOE OR Bcf) | MMBbls			55				61
Natural gas (in cubic feet) | Short position
Outstanding commodity derivatives contracts not designated as hedging instruments
Commodity contracts Volume (MMBOE OR Bcf) | Bcf		128				142

XML

LONG-TERM DEBT - SCHEDULE (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term debt, gross	$ 37,400,000,000	$ 10,407,000,000
Unamortized discount, net		(36,000,000)
Debt issuance costs		(54,000,000)
Long-term finance leases	347,000,000
Current maturities	(51,000,000)	(116,000,000)
Total	38,537,000,000	$ 10,201,000,000
Occidental
Debt Instrument [Line Items]
Long-term debt, gross	37,401,000,000
Unamortized discount, net	914,000,000
Debt issuance costs	(125,000,000)
Long-term finance leases	347,000,000
Long-term debt	$ 38,537,000,000
4.850% senior notes due 2021 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.85%
Long-term debt, gross	$ 677,000,000
2.600% senior notes due 2021 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	2.60%
Long-term debt, gross	$ 1,500,000,000
4.100% senior notes due 2021 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		4.10%
Long-term debt, gross		$ 1,249,000,000
4.100% senior notes due 2021 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.10%
Long-term debt, gross	$ 1,249,000,000
Variable rate bonds due 2021, 2.854% | Variable rate bonds | Occidental
Debt Instrument [Line Items]
Debt instrument, variable rate	2.854%
Long-term debt, gross	$ 500,000,000
Variable rate bonds due 2021, 3.151% | Variable rate bonds | Occidental
Debt Instrument [Line Items]
Debt instrument, variable rate	3.151%
Long-term debt, gross	$ 500,000,000
2-year variable rate Term Loan due 2021, 3.111% | Secured Debt | Occidental
Debt Instrument [Line Items]
Debt instrument, variable rate	3.111%
Debt instrument, term	2 years
Long-term debt, gross	$ 1,956,000,000
2.700% senior notes due 2022 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	2.70%
Long-term debt, gross	$ 2,000,000,000
3.125% senior notes due 2022 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		3.125%
Long-term debt, gross		$ 813,000,000
3.125% senior notes due 2022 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	3.125%
Long-term debt, gross	$ 814,000,000
2.600% senior notes due 2022 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		2.60%
Long-term debt, gross		$ 400,000,000
2.600% senior notes due 2022 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	2.60%
Long-term debt, gross	$ 400,000,000
Variable rate bonds due 2022, 3.360% | Variable rate bonds | Occidental
Debt Instrument [Line Items]
Debt instrument, variable rate	3.36%
Long-term debt, gross	$ 1,500,000,000
2.700% senior notes due 2023 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		2.70%
Long-term debt, gross		$ 1,191,000,000
2.700% senior notes due 2023 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	2.70%
Long-term debt, gross	$ 1,191,000,000
8.750% medium-term notes due 2023 | Medium-term notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		8.75%
Long-term debt, gross		$ 22,000,000
8.750% medium-term notes due 2023 | Medium-term notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	8.75%
Long-term debt, gross	$ 22,000,000
2.900% senior notes due 2024 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	2.90%
Long-term debt, gross	$ 3,000,000,000
6.950% senior notes due 2024 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	6.95%
Long-term debt, gross	$ 650,000,000
3.450% senior notes due 2024 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	3.45%
Long-term debt, gross	$ 248,000,000
3.500% senior notes due 2025 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		3.50%
Long-term debt, gross		$ 750,000,000
3.500% senior notes due 2025 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	3.50%
Long-term debt, gross	$ 750,000,000
5.550% senior notes due 2026 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	5.50%
Long-term debt, gross	$ 1,100,000,000
3.200% senior notes due 2026 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	3.20%
Long-term debt, gross	$ 1,000,000,000
3.400% senior notes due 2026 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		3.40%
Long-term debt, gross		$ 1,150,000,000
3.400% senior notes due 2026 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	3.40%
Long-term debt, gross	$ 1,150,000,000
7.500% debentures due 2026 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.50%
Long-term debt, gross	$ 112,000,000
3.000% senior notes due 2027 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		3.00%
Long-term debt, gross		$ 750,000,000
3.000% senior notes due 2027 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	3.00%
Long-term debt, gross	$ 750,000,000
7.125% debentures due 2027 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.125%
Long-term debt, gross	$ 150,000,000
7.000% debentures due 2027 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.00%
Long-term debt, gross	$ 48,000,000
6.625% debentures due 2028 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	6.625%
Long-term debt, gross	$ 14,000,000
7.150% debentures due 2028 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.15%
Long-term debt, gross	$ 235,000,000
7.200% senior debentures due 2028 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		7.20%
Long-term debt, gross		$ 82,000,000
7.200% senior debentures due 2028 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.20%
Long-term debt, gross	$ 82,000,000
7.200% debentures due 2029 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.20%
Long-term debt, gross	$ 135,000,000
7.950% debentures due 2029 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.95%
Long-term debt, gross	$ 116,000,000
8.450% senior debentures due 2029 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		8.45%
Long-term debt, gross		$ 116,000,000
8.450% senior debentures due 2029 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	8.45%
Long-term debt, gross	$ 116,000,000
3.500% senior notes due 2029 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	3.50%
Long-term debt, gross	$ 1,500,000,000
Variable rate bonds due 2030, 1.705% | Variable rate bonds | Occidental
Debt Instrument [Line Items]
Debt instrument, variable rate	1.705%
Long-term debt, gross	$ 68,000,000
7.500% senior notes due 2031 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.50%
Long-term debt, gross	$ 900,000,000
7.875% senior notes due 2031 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.875%
Long-term debt, gross	$ 500,000,000
6.450% senior notes due 2036 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	6.45%
Long-term debt, gross	$ 1,750,000,000
Zero Coupon senior notes due 2036 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	5.24%
Face value	$ 2,300,000,000
Zero Coupon senior notes due 2036 | Senior notes | Occidental
Debt Instrument [Line Items]
Long-term debt, gross	$ 2,271,000,000
6.500% note payable to WES due 2038 | Note payable | WES
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	6.50%
Long-term debt, gross	$ 260,000,000
4.300% senior notes due 2039 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.30%
Long-term debt, gross	$ 750,000,000
7.950% senior notes due 2039 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.95%
Long-term debt, gross	$ 325,000,000
6.200% senior notes due 2040 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	6.20%
Long-term debt, gross	$ 750,000,000
4.500% senior notes due 2044 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.50%
Long-term debt, gross	$ 625,000,000
4.625% senior notes due 2045 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		4.625%
Long-term debt, gross		$ 750,000,000
4.625% senior notes due 2045 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.625%
Long-term debt, gross	$ 750,000,000
6.600% senior notes due 2046 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	6.60%
Long-term debt, gross	$ 1,100,000,000
4.400% senior notes due 2046 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		4.40%
Long-term debt, gross		$ 1,200,000,000
4.400% senior notes due 2046 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.40%
Long-term debt, gross	$ 1,200,000,000
4.100% senior notes due 2047 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		4.10%
Long-term debt, gross		$ 750,000,000
4.100% senior notes due 2047 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.10%
Long-term debt, gross	$ 750,000,000
4.200% senior notes due 2048 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		4.20%
Long-term debt, gross		$ 1,000,000,000
4.200% senior notes due 2048 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.20%
Long-term debt, gross	$ 1,000,000,000
4.400% senior notes due 2049 | Senior notes | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	4.40%
Long-term debt, gross	$ 750,000,000
7.730% debentures due 2096 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.73%
Long-term debt, gross	$ 60,000,000
7.500% debentures due 2096 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.50%
Long-term debt, gross	$ 78,000,000
7.250% debentures due 2096 | Debentures | Occidental
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.25%
Long-term debt, gross	$ 49,000,000
9.250% senior debentures due 2019 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage		9.25%
Long-term debt, gross		$ 116,000,000
Variable rate bonds due 2030, 1.9% | Variable rate bonds
Debt Instrument [Line Items]
Debt instrument, variable rate		1.90%
Long-term debt, gross		$ 68,000,000
Senior Notes due 2025 | Senior notes
Debt Instrument [Line Items]
Debt instrument interest rate stated percentage	7.25%
Face value	$ 310,000

XML

LEASE COMMITMENTS - SCHEDULE OF OPERATING AND FINANCE LEASE MATURITIES (Details) - USD ($) $ in Millions	Dec. 31, 2019	Aug. 08, 2019
Operating Leases
2019		$ 90
2020	$ 555	172
2021	408	64
2022	136	42
2023	99	28
2024	81
Thereafter		136
Thereafter	254
Total lease payments	1,533	532
Less: Interest	(110)	(44)
Total lease liabilities	1,423	488
Finance Leases
2019		7
2020	53	17
2021	45	16
2022	41	13
2023	37	8
2024	34
Thereafter		43
Thereafter	275
Total lease payments	485	104
Less: Interest	(87)	(18)
Total lease liabilities	398	86
Total
2019		97
2020	608	189
2021	453	80
2022	177	55
2023	136	36
2024	115
Thereafter		179
Thereafter	529
Total lease payments	2,018	636
Less: Interest	(197)	(62)
Total lease liabilities	1,821	574
Lease liability	1,423	488
Finance lease	$ 398	$ 86
Weighted average lease term, operating lease	4 years 7 months 6 days
Weighted average discount rate, operating lease	2.53%
Weighted average lease term, finance lease	11 years 7 months 6 days
Weighted average discount rate, finance lease	3.74%
Anadarko's Africa Assets | Disposed of by sale
Operating Leases
Total lease liabilities	$ 74
Finance Leases
Total lease liabilities	201
Total
Lease liability	74
Finance lease	$ 201

XML

ENVIRONMENTAL LIABILITIES AND EXPENDITURES (Details)	1 Months Ended	3 Months Ended	12 Months Ended
	Mar. 31, 2016 mi	Sep. 30, 2016 USD ($)	Dec. 31, 2019 USD ($) site	Dec. 31, 2018 USD ($) site	Dec. 31, 2017 USD ($)
Environmental remediation reserves
Number of Sites			177	145
Environmental remediation reserves, current, included in accrued liabilities | $			$ 162,000,000	$ 120,000,000
Environmental remediation reserves, noncurrent, included in deferred credits and other liabilities - other | $			1,035,000,000	762,000,000
Remediation balance | $			1,197,000,000	882,000,000
Environmental reserves, exceeding $ ten million, threshold value | $			$ 10,000,000
Environmental reserves, exceeding $ ten million, number of sites			20
Environmental reserves, range between zero to $ one million site category, number of sites			101
Remediation Expenses | $			$ 112,000,000	$ 47,000,000	$ 39,000,000
Percent of reserve to be funded over the next three to four years			40.00%
Minimum period of expending second half of environmental reserves			10 years
Environmental remediation additional loss range | $			$ 1,100,000,000
Low end of range
Environmental remediation reserves
Environmental reserves, range between zero to $ one million site category | $			$ 0
Period of expending 40 percent of environmental reserves			3 years
High end of range
Environmental remediation reserves
Environmental reserves, range between zero to $ one million site category | $			$ 1,000,000
Period of expending 40 percent of environmental reserves			4 years
NPL sites
Environmental remediation reserves
Number of Sites			36	34
Remediation balance | $			$ 463,000,000	$ 458,000,000
Number of sites with significant environmental remediation reserves			5
Percentage of environmental reserves accounted for by associated sites			94.00%
Number of sites indemnified by third party			17
Third-party sites
Environmental remediation reserves
Number of Sites			74	68
Remediation balance | $			$ 311,000,000	$ 168,000,000
Number of sites with significant environmental remediation reserves			6
Percentage of environmental reserves accounted for by associated sites			75.00%
Number of sites indemnified by third party			74
Number of sites not indemnified by third party			74
Occidental-operated sites
Environmental remediation reserves
Number of Sites			17	14
Remediation balance | $			$ 154,000,000	$ 115,000,000
Number of sites with significant environmental remediation reserves			3
Percentage of environmental reserves accounted for by associated sites			67.00%
Closed or non-operated Occidental sites
Environmental remediation reserves
Number of Sites			50	29
Remediation balance | $			$ 269,000,000	$ 141,000,000
Number of sites with significant environmental remediation reserves			6
Percentage of environmental reserves accounted for by associated sites			64.00%
Maxus
Environmental remediation reserves
Number of sites indemnified by third party			9
Passaic River
Environmental remediation reserves
Stretch of Lower Passaic river requiring remedial actions | mi	8.3
River stretch which may require remedial actions | mi	9
Clean-up estimated cost | $		$ 165,000,000
Anadarko Petroleum Corporation
Environmental remediation reserves
Number of Sites			36

XML

INCOME TAXES - COMPONENTS OF INCOME TAX EXPENSE (BENEFIT) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current
Federal	$ 33	$ (23)	$ (81)
State and Local	46	52	11
Foreign	1,641	1,077	806
Total current tax expense	1,720	1,106	736
Deferred
Federal	(130)	422	(856)
State and Local	17	12	23
Foreign	(914)	(63)	114
Total deferred tax expense (benefit)	(1,027)	371	(719)
Total income tax expense	$ 693	$ 1,477	$ 17

XML

DERIVATIVES - SUMMARY OF DERIVATIVE INSTRUMENTS (Details) - Oil	Dec. 31, 2019 ThousandBarrels / d $ / Barrel
2020 Settlement
Derivative [Line Items]
Derivative instruments (mmbls/day) | ThousandBarrels / d	128,100
2020 Settlement | Short position
Derivative [Line Items]
Ceiling sold price (dollars per barrel)	74.16
Purchase price (dollars per barrel)	45.00
2020 Settlement | Long position
Derivative [Line Items]
Purchase price (dollars per barrel)	55.00
2021 Settlement
Derivative [Line Items]
Derivative instruments (mmbls/day) | ThousandBarrels / d	127,800
2021 Settlement | Short position
Derivative [Line Items]
Ceiling sold price (dollars per barrel)	74.16

XML

DERIVATIVES

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

NOTE 9 - DERIVATIVES

OBJECTIVE AND STRATEGY

Occidental uses a variety of derivative financial instruments and physical contracts to manage its exposure to commodity-price fluctuations, interest rate risks, transportation commitments, and to fix margins on the future sale of stored commodity volumes. Occidental also enters into derivative financial instruments for trading purposes.

Occidental may elect normal purchases and normal sales exclusions when physically delivered commodities are purchased or sold to a customer. Occidental occasionally applies cash flow hedge accounting treatment to derivative financial instruments to lock in margins on the forecasted sales of its natural gas storage volumes, and at times for other strategies, such as to lock rates on forecasted debt issuances. Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. See Note 1 - Summary of Significant Accounting Policies for Occidental’s accounting policy on derivatives.

DERIVATIVES NOT DESIGNATED AS HEDGING INSTRUMENTS

As of December 31, 2019, Occidental’s derivatives not designated as hedges consist of three-way oil collars and call options, interest rate swaps, marketing derivatives and the Warrant.

Derivative instruments that are derivatives not designated as hedging instruments are required to be recorded on the balance sheet at fair value. Changes in fair value will impact Occidental’s earnings through mark-to-market adjustments until the physical commodity is delivered or the financial instrument is settled. The fair value does not reflect the realized or cash value of the instrument.

THREE-WAY OIL COLLARS AND CALL OPTIONS

In 2019, Occidental entered into three-way costless collar derivative instruments for 2020 along with additional call options in 2021 to manage its near-term exposure to cash-flow variability from commodity price risks. A three-way collar is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price that Occidental will receive for the contracted commodity volume for a defined period of time. The purchased put establishes the floor price that Occidental will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the floor price equals the reference price plus the difference between the purchased put strike price and the sold put strike price for a defined period of time. Occidental entered into the 2021 call options to substantially improve the terms for the ceiling price that Occidental will receive for the contracted commodity volumes in 2020. Net gains and losses associated with collars and calls are recognized currently in net sales.

Occidental had the following collars and calls outstanding at December 31, 2019:

Collars and Calls, not designated as hedges
2020 Settlement
Three-way collars (oil MMBBL)			128.1
	Volume weighted average price per barrel (Brent oil pricing)
		Ceiling sold price (call)	$	74.16
		Floor purchased price (put)	$	55.00
		Floor sold price (put)	$	45.00
2021 Settlement
Call options sold (oil MMBBL)			127.8
	Volume weighted average price per barrel (Brent oil pricing)
		Ceiling sold price (call)	$	74.16

INTEREST RATE SWAPS

Occidental acquired interest rate swap contracts in the Acquisition. The contracts lock in a fixed interest rate in exchange for a floating interest rate indexed to three-month London Inter-Bank Offered Rate (LIBOR) throughout the reference period. Occidental also acquired interest rate swap contracts held by WES, which were settled as of December 31, 2019. Net gains and losses associated with interest rate derivative instruments not designated as hedging instruments are recognized currently in gains (losses) on interest rate swaps and warrants, net.

Occidental had the following outstanding interest rate swaps at December 31, 2019:

millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418	%
$	125	September 2016 - 2046	September 2022	6.835	%
$	100	September 2017 - 2047	September 2020	6.891	%
$	250	September 2017 - 2047	September 2021	6.570	%
$	450	September 2017 - 2047	September 2023	6.445	%

Depending on market conditions, liability management actions or other factors, Occidental may enter into offsetting interest rate swap positions or settle or amend certain or all of the currently outstanding interest rate swaps. Occidental settled interest rate swaps with a notional value of $125 million in October 2019. In January and February 2020, Occidental extended September 2020 mandatory termination dates to September 2021 and September 2022 for swaps with a notional value of $500 million and $150 million, respectively.

Derivative settlements and collateralization are classified as cash flows from operating activities unless the derivatives contain an other-than-insignificant financing element, in which case the settlements and collateralization are classified as cash flows from financing activities. Due to the liability position of the interest rate derivatives at the date of the Acquisition, the interest rate derivatives in Occidental’s portfolio contain an other-than-insignificant financing element, and therefore, any settlements, collateralization or cash payments related to interest rate derivatives are classified as cash flow from financing activities. Net cash receipts related to settlements, and collateralization of interest rate swap agreements were $120 million during the period from August 8, 2019 through December 31, 2019.

MARKETING DERIVATIVES

Occidental’s marketing derivative instruments not designated as hedges are physical and financial forward contracts which typically settle within three months. A substantial majority of Occidental’s physically settled derivative contracts are index-based and carry no mark-to-market valuation in earnings. These instruments settle at a weighted-average contract price of $60.60 per barrel and $2.17 per thousand cubic feet (Mcf) for oil and natural gas, respectively, at December 31, 2019. The weighted-average contract price was $58.81 per barrel and $3.18 per Mcf for oil and natural gas, respectively, at December 31, 2018. Net gains and losses associated with marketing derivative instruments not designated as hedging instruments are recognized currently in net sales.

The following table summarizes net long/(short) volumes associated with the outstanding marketing commodity derivatives not designated as hedging instruments as of December 31, 2019, and 2018:

	2019		2018
Oil Commodity Contracts
Volume (MMBBL)	55		61
Natural gas commodity contracts
Volume (Bcf)	(128	)	(142	)

THE WARRANT

The Warrant issued with the Preferred Stock in connection with the Acquisition is exercisable at the holder’s option, in whole or in part, until the first anniversary of the date on which no shares of Preferred Stock remain outstanding at which point the Warrant expires. The holder of the Warrant may require net cash settlement if certain shareholder and regulatory approvals to issue Occidental common stock are not obtained on a timely basis. The initial fair value of the Warrant, $188 million, was measured at the date of the Acquisition using the Black Scholes option model. The following inputs were used in the Black Scholes option model: the expected life is based on the estimated term of the Warrant, the volatility factor is based on historical volatilities of Occidental common stock, and the call option price for Occidental common stock at $62.50. The fair value of the Warrant is remeasured each reporting period based on changes in the inputs above.

DERIVATIVES DESIGNATED AS HEDGING INSTRUMENTS

Net gains and losses attributable to derivative instruments subject to cash flow hedge accounting reside in accumulated other comprehensive loss and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings.

CASH FLOW HEDGES

Occidental’s marketing operations store natural gas purchased from third parties at Occidental’s leased storage facilities. Occidental occasionally elects cash flow hedge accounting for derivative instruments which are used to fix margins on the future sales of the stored volumes. The amount of cash flow hedges related to stored gas, including the ineffective portion, was immaterial for the years ended December 31, 2019, and 2018.

In June 2019, in anticipation of issuing debt in the third quarter to partially finance the cash portion of the Acquisition consideration, Occidental entered into a series of U.S. treasury locks which were designated as cash flow hedges. In August 2019, the U.S. treasury locks were unwound with the issuance of the $13.0 billion new senior unsecured notes, and the resulting after-tax accumulated other comprehensive loss of $125 million will be amortized to interest expense over the life of the underlying senior notes.

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 presents the fair values of Occidental’s outstanding derivatives. Fair values are presented at gross amounts below, including when derivatives are subject to netting arrangements, and are presented on a net basis in the Consolidated Balance Sheets.

millions	Fair Value Measurements Using											Total Fair Value
Balance Sheet Classification	Level 1			Level 2			Level 3		Netting (a)
December 31, 2019
Oil Collars and Calls
Other current assets	$	—		$	92		$	—	$	—		$	92
Deferred credits and other liabilities - other	—			(160		)	—		—			(160		)
Marketing Derivatives
Other current assets	945			79			—		(973		)	51
Long-term receivables and other assets, net	4			12			—		(4		)	12
Accrued liabilities	(1,008		)	(44		)	—		973			(79		)
Deferred credits and other liabilities - other	(4		)	(1		)	—		4			(1		)
Interest Rate Swaps
Other current assets	—			5			—		—			5
Long-term receivables and other assets, net	—			5			—		—			5
Accrued liabilities	—			(657		)	—		—			(657		)
Deferred credits and other liabilities - other	—			(776		)	—		—			(776		)
Warrant
Deferred credits and other liabilities - other	—			(107		)	—		—			(107		)
December 31, 2018
Marketing Derivatives
Other current assets	$	2,531		$	110		$	—	$	(2,392	)	$	249
Long-term receivables and other assets, net	5			9			—		(6		)	8
Accrued liabilities	(2,357		)	(101		)	—		2,392			(66		)
Deferred credits and other liabilities - other	(6		)	(2		)	—		6			(2		)

^(a)  These amounts do not include collateral. As of December 31, 2019, $104 million of collateral has been netted against derivative liabilities related to interest rate swaps. Occidental had $65 million and $54 million of initial margin deposited with brokers as of December 31, 2019 and 2018, respectively, related to marketing derivatives.

GAINS AND LOSSES ON DERIVATIVES

The following table presents gains and (losses) related to Occidental’s derivative instruments on the Consolidated Statements of Operations:

millions	December 31,
Income Statement Classification	2019			2018		2017
Oil Collars and Calls
Net sales	$	(107	)	$	—	$	—
Marketing Derivatives
Net sales (a)	1,804			2,254		(138		)
Interest Rate Swaps (Excluding WES)
Gain on interest rate swaps and warrants, net	122			—		—
Interest Rate Swaps (WES)
Gain on interest rate swaps and warrants, net	30			—		—
Warrant
Gain on interest rate swaps and warrants, net	81			—		—

^(a)  Included derivative and non-derivative marketing activity.

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 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 party would need to post. The aggregate fair value of derivative instruments with credit-risk-contingent features for which a net liability position existed at December 31, 2019 was $787 million (net of $169 million collateral), primarily related to acquired interest-rate swaps, and $68 million (net of $1 million of collateral) existed at December 31, 2018.

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REVENUE

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

REVENUE

NOTE 5 - REVENUE

Revenue from customers is recognized when obligations under the terms of a contract are satisfied; this generally occurs with the delivery of oil, gas, NGL, chemicals or services such as transportation. Revenue from customers is measured as the amount of consideration Occidental expects to receive in exchange for the delivery of goods or services. Contracts may last from one month to one year or more, and may have renewal terms that extend indefinitely at the option of either party. Price is typically based on market indexes. Volumes fluctuate due to production and, in certain cases, customer demand and transportation availability. Occidental records revenue net of certain taxes, such as sales taxes, that are assessed by governmental authorities on Occidental’s customers.

Occidental does not incur significant costs to obtain contracts. Incidental items that are immaterial in the context of the contract are recognized as expenses. Sales of hydrocarbons and chemicals to customers are invoiced and settled on a monthly basis. Occidental is not usually subject to obligations for warranties, rebates, returns or refunds except in the case of customer incentive payments as discussed for the chemical segment below. Occidental does not typically receive payment in advance of satisfying its obligations under the terms of its sales contracts with customers; therefore, liabilities related to such payment are immaterial to Occidental.

OIL AND GAS SEGMENT

Revenue from oil and gas production is recognized when production is delivered and control passes to the customer. 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.

CHEMICALS SEGMENT

Revenue from chemical product sales is recognized when control passes 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. Customer incentives are estimated and recorded as a reduction to revenue ratably over the contract period. Such estimates are evaluated and revised as warranted. Revenue from exchange contracts is excluded from revenue from customers.

MARKETING AND MIDSTREAM SEGMENT

Revenue from pipeline and gas processing is recognized upon the completion of the transportation or processing service. Revenue from power sales is recognized upon delivery. Net marketing revenue is included in net sales, but excluded from revenue from customers in the table below. Net marketing revenue is recognized upon completion of contract terms that are a prerequisite to payment and upon title transfer for physical deliveries. Unless the normal purchases and sales exception has been elected, net marketing revenue is classified as a derivative, reported on a net basis, recorded at fair value and changes in fair value are reflected in net sales.

The following table reconciles revenue from customers to total net sales for the years ended December 31:

millions	2019		2018
Revenue from customers	$	18,674	$	15,560
All other revenues (a)	1,719		2,264
Net sales	$	20,393	$	17,824

^(a)  Included net marketing derivatives, oil collars and calls and chemical exchange contracts.

DISAGGREGATION OF REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table presents Occidental’s revenue from customers by segment, product and geographical area. The oil and gas segment typically sells its oil, gas and NGL at the lease or concession area. Chemical revenues are shown by geographic area based on the location of the sale. Marketing and midstream revenues are shown by the location of sale.

millions	United States			Middle East			Latin America		Other International		Eliminations			Total
Year ended December 31, 2019
Oil and Gas
Oil	$	8,411		$	2,758		$	683	$	—	$	—		$	11,852
NGL	658			263			—		—		—			921
Gas	424			319			20		—		—			763
Other	(1		)	(5		)	—		—		—			(6		)
Segment total	$	9,492		$	3,335		$	703	$	—	$	—		$	13,530
Chemical	$	3,858		$	—		$	155	$	67	$	—		$	4,080
Marketing and Midstream (a)
Gas processing	$	395		$	351		$	—	$	—	$	—		$	746
WES - Gas processing and pipeline	1,110			—			—		—		—			1,110
Power and other	472			—			—		—		—			472
Segment total	$	1,977		$	351		$	—	$	—	$	—		$	2,328
Eliminations	$	—		$	—		$	—	$	—	$	(1,264	)	$	(1,264	)
Consolidated	$	15,327		$	3,686		$	858	$	67	$	(1,264	)	$	18,674
Year ended December 31, 2018
Oil and Gas
Oil	$	5,125		$	3,405		$	715	$	—	$	—		$	9,245
NGL	430			261			—		—		—			691
Gas	185			294			16		—		—			495
Other	7			3			—		—		—			10
Segment total	$	5,747		$	3,963		$	731	$	—	$	—		$	10,441
Chemical	$	4,363		$	—		$	205	$	80	$	—		$	4,648
Marketing and Midstream
Gas processing	$	557		$	425		$	—	$	—	$	—		$	982
Pipelines	311			—			—		—		—			311
Power and other	108			—			—		—		—			108
Segment total	$	976		$	425		$	—	$	—	$	—		$	1,401
Eliminations	$	—		$	—		$	—	$	—	$	(930	)	$	(930	)
Consolidated	$	11,086		$	4,388		$	936	$	80	$	(930	)	$	15,560

^(a)  The marketing and midstream segment included revenues from customers from WES from the date of the Acquisition to December 31, 2019. See Note 1 - Summary of Significant Accounting Policies. 

TRANSACTION PRICE ALLOCATED TO REMAINING PERFORMANCE OBLIGATIONS

Revenue expected to be recognized from certain performance obligations that are unsatisfied as of December 31, 2019, is reflected in the table below. Occidental applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. As a result, the following table represents a small portion of Occidental’s expected future consolidated revenues, as future revenue from the sale of most products and services is dependent on future production or variable customer volume and variable commodity prices for that volume:

millions	Total
2020	$	103
2021	103
2022	7
2023	7
2024	7
Thereafter	53
Total	$	280

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

In this report, “Occidental” means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental conducts its operations through various subsidiaries and affiliates. On August 8, 2019, pursuant to the Agreement and Plan of Merger, dated as of May 9, 2019 (the Merger Agreement), among Occidental, Baseball Merger Sub 1, Inc., a Delaware corporation and an indirect, wholly owned subsidiary of Occidental (Merger Subsidiary), and Anadarko Petroleum Corporation (Anadarko), Occidental acquired all of the outstanding shares of Anadarko through a transaction in which Merger Subsidiary merged with and into Anadarko (the Acquisition), with Anadarko continuing as the surviving entity and as an indirect, wholly owned subsidiary of Occidental. See Note 3 - The Acquisition.

Occidental’s principal businesses consist of three reporting segments: oil and gas, chemical and marketing and midstream. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The marketing and midstream segment purchases, markets, gathers, processes, transports and stores oil, condensate, NGL, natural gas, carbon dioxide (CO₂) and power. It also trades around its assets, including transportation and storage capacity, and invests in entities that conduct similar activities. Included in the marketing and midstream segment is Occidental’s equity method investment in Western Midstream Partners, L.P. (WES). WES owns gathering systems, plants and pipelines and earns revenue from fee-based and service-based contracts with Occidental and third parties. Also within the marketing and midstream segment is Oxy Low Carbon Ventures (OLCV). OLCV seeks to capitalize on Occidental’s enhanced oil recovery (EOR) leadership by developing carbon capture, utilization and storage projects that source anthropogenic CO₂ and promote innovative technologies that drive cost efficiencies and economically grow Occidental’s business while reducing emissions.

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, variable interest entities (VIE) for which Occidental is the primary beneficiary, 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, statements of operations and statements of cash flows.

The Acquisition introduced different revenue and expense streams to Occidental’s legacy operations. As a result, changes were made to the structure of certain financial statements, notes and supplementary data to provide clarity and to conform to the current presentation.

WES INVESTMENT

WES is a publicly traded limited partnership with its common units traded on the New York Stock Exchange (NYSE) under the ticker symbol “WES.” WES owns the entire non-economic general partner interest and a 98% limited partner interest in Western Midstream Operating, LP (WES Operating), a Delaware limited partnership formed by Anadarko in 2007 to acquire, own, develop and operate midstream assets. WES maintains its own capital structure that is separate from Occidental, consisting of its own debt instruments and publicly traded common units.

From the Acquisition date through December 31, 2019, WES was determined to be a VIE, and Occidental, through its ownership of the general partner interest in WES, had the power to direct the activities that significantly affected the economic performance of WES and the obligation to absorb losses or the right to receive benefits that could be significant to WES. As such, Occidental was considered the primary beneficiary and consolidated WES and its consolidated subsidiaries from the date of the Acquisition to December 31, 2019. All intercompany transactions were eliminated during the consolidated period. Revenues of $1.1 billion, cost of sales of $500 million and operating cash flows of $498 million from the date of the Acquisition to December 31, 2019 are attributable to WES and are included in Occidental’s consolidated financial statements. Net income from noncontrolling interest for the same period relates to the 44.6% limited partner interest of WES owned by the public.

On December 31, 2019, Occidental and WES executed several agreements to allow WES to operate as an independent midstream company to support its ongoing pursuit of third-party growth opportunities. The executed agreements include amendments to the partnership agreement that significantly expand the unaffiliated limited partner unitholders’ rights. The significant amendments to the partnership agreement included:

Ø Providing for a simple majority of the unaffiliated unitholders to remove and elect a new general partner;

Ø Allowing for 20% of the unaffiliated unitholders to call a special meeting to vote to remove the general partner;

Ø Eliminating ownership thresholds that could have prevented unaffiliated unitholders from voting;

Ø Limiting Occidental’s voting percentage to 45% for certain unitholder matters until Occidental owns less than 40% of the limited partner units for twelve consecutive months; and

Ø Transferring 2% of Occidental’s limited partner interest to the general partner to provide a 2% economic interest to the general partner.

In addition to the partnership agreement amendments, in December 2019, the WES management team’s employment was transferred from Occidental to WES, and WES-dedicated personnel were seconded to WES from Occidental. The seconded employees’ employment is contractually obligated to be transferred to WES during 2020 once employee benefit plans are established. Additionally, as of December 31, 2019, Occidental employees no longer comprise a majority of the board of directors of WES’s general partner.

As a result of the partnership agreement amendments and other related agreements, WES no longer met the criteria to be considered a VIE. Accordingly, Occidental evaluated WES under the voting interest model and determined, because Occidental did not control the power to appoint or remove a successor general partner, it should no longer consolidate WES.

As a result of the loss of control, Occidental derecognized all assets, liabilities, and noncontrolling interest that were previously consolidated. Occidental recognized, at fair value, an equity method investment of $5.1 billion based on the closing market price of WES as of December 31, 2019 and recognized a loss of approximately $1 billion that is included in asset impairments and other charges on the Statement of Operations. In future periods, Occidental will recognize equity method earnings and dividends received for its economic interest in WES.

As of December 31, 2019, Occidental has a 55.4% unit ownership in WES, which consists of a 2% non-voting general partner unit interest and 54.5% of limited partner unit interest. In addition, Occidental has a 2% non-voting limited partner interest in WES Operating, which brings Occidental’s total effective economic interest in WES and its subsidiaries to 56.3%. During 2020, Occidental intends to reduce its limited partner ownership interest in WES to below 50%. Occidental’s historical pro rata interest in the net assets of WES was $1.9 billion, resulting in a basis difference of $3.2 billion primarily associated with WES’s equity method investments, PP&E, equity method goodwill and intangible assets - customer relationships and subject to amortization over their estimated average useful life.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates for 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.

DISCONTINUED OPERATIONS

In connection with the Acquisition, Occidental agreed to sell to TOTAL S.A. (Total) all of the assets, liabilities, businesses, and operations of Anadarko’s operations in Algeria, Ghana, Mozambique and South Africa (collectively, the Africa Assets) for $8.8 billion, subject to certain purchase price adjustments. In August 2019, a purchase and sale agreement was executed for these Africa Assets. This transaction is conditioned on the receipt of required regulatory approvals, as well as other customary closing conditions. In September 2019, Occidental completed the sale of Mozambique LNG assets to Total for $4.2 billion. The assets and liabilities for Algeria, Ghana and South Africa are presented as held for sale at December 31, 2019. The results of operations of the Africa Assets are presented as discontinued operations, see Note 4 - Acquisitions, Dispositions and Other Transactions. In January 2020, Occidental completed the sale of South Africa assets to Total.

Unless otherwise indicated, information presented in the Notes to the Consolidated Financial Statements relates only to Occidental’s continuing operations. Information related to discontinued operations is included in Note 4 - Acquisitions, Dispositions and Other Transactions, and in some instances, where appropriate, is included as a separate disclosure within the individual Notes to the Consolidated Financial Statements.

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with GAAP requires Occidental’s management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements. Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets 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 $14.9 billion as of December 31, 2019, and net sales of approximately $4.6 billion for the year ended December 31, 2019, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that have experienced political instability, nationalizations, corruption, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions, all of which increase Occidental’s risk of loss, 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 EQUIVALENTS AND RESTRICTED CASH EQUIVALENTS

Occidental considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents or restricted cash equivalents. The cash equivalents and restricted cash equivalents balance at December 31, 2019, included investments in government money market funds in which the carrying value approximates fair value.

The following table provides a reconciliation of cash, cash equivalents, restricted cash and restricted cash equivalents as reported at the end of the period in the Consolidated Statements of Cash Flows for the twelve months ended December 31, 2019 to the line items within the Consolidated Balance Sheet at December 31, 2019. There was no restricted cash or restricted cash equivalents at December 31, 2018.

millions	December 31, 2019
Cash and cash equivalents	$	3,032
Restricted cash and restricted cash equivalents	480
Cash and restricted cash included in assets held for sale	8
Restricted cash and restricted cash equivalents included in long-term receivables and other assets, net	54
Cash, cash equivalents, restricted cash, and restricted cash equivalents	$	3,574

Total restricted cash and restricted cash equivalents are primarily associated with a benefits trust for former Anadarko employees, payments of future hard-minerals royalties conveyed, and a judicially-controlled account related to a Brazilian tax dispute.

RECEIVABLES AND OTHER CURRENT ASSETS

Trade receivables, net, of $6.4 billion and $4.9 billion at December 31, 2019, and 2018, respectively, represent rights to payment for which Occidental has satisfied its obligations under a contract with a customer and its right to payment is conditioned only on the passage of time.

Other current assets included amounts receivable from working interest partners in Occidental’s oil and gas operations, derivative assets, and taxes receivable.

INVENTORIES

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

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

PROPERTY, PLANT AND EQUIPMENT

OIL AND GAS

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and 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. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities, in particular, whether Occidental is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, analyzing whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

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

millions	2019			2018			2017
Balance — beginning of year	$	112		$	108		$	56
Exploratory well costs acquired through the Acquisition	231			—			—
Additions to capitalized exploratory well costs pending the determination of proved reserves	383			220			201
Reclassifications to property, plant and equipment based on the determination of proved reserves	(230		)	(198		)	(128		)
Capitalized exploratory well costs charged to expense	(72		)	(18		)	(21		)
Balance — end of year	$	424		$	112		$	108

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 leasehold 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 performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to prolonged declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include future production and timing of production, estimates of future product prices, contractual prices, estimates of risk-adjusted oil and gas reserves and estimates of future operating and development costs. See Note 17 - Fair Value Measurements and below for further discussion of asset impairments.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. Net capitalized costs attributable to unproved properties were $29.5 billion at December 31, 2019 and $1.0 billion December 31, 2018. The unproved amounts are not subject to DD&A until they are classified as proved properties. Individually insignificant unproved properties are combined and amortized on a group basis based on factors such as lease terms, success rates, and other factors. If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. Occidental periodically reviews unproved properties for impairments; numerous factors are considered, including but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property or the adjacent property, geologists’ evaluation of the property and the remaining lease term for the property. Management’s assessment of the availability of funds for future activities and the current and projected political and regulatory climate in areas in which Occidental operates also impacts the timing of any impairment.

CHEMICAL

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

Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are affected by domestic and international 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.

MARKETING AND MIDSTREAM

Occidental’s marketing and midstream 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 marketing and midstream 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.

GOODWILL

Occidental recognized goodwill of $5.8 billion associated with the Acquisition. The goodwill was based on WES’s publicly traded units and was primarily associated with the relationship between Occidental and WES as well as Occidental’s tax basis in WES. Upon loss of control and application of the equity method of accounting, $4.6 billion of goodwill was derecognized. The remaining $1.2 billion in goodwill is assigned to the marketing and midstream segment and is attributable to the deferred tax liability associated with the investment in WES.

Goodwill is subject to annual impairment testing every October. Occidental’s goodwill impairment test first assesses qualitative factors to determine whether goodwill is likely impaired. If the qualitative assessment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount including goodwill, Occidental will then perform a quantitative goodwill impairment test. Changes in goodwill may result from, among other things, impairments, future acquisitions, or future divestitures.

IMPAIRMENTS AND OTHER CHARGES

During 2019, Occidental’s Oil and Gas segment recognized pre-tax impairment and related charges of $285 million related to domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and $39 million related to Occidental’s mutually agreed early termination of its Qatar Idd El Shargi South Dome (ISSD) contract.

During 2018, Occidental recognized pre-tax impairment and related charges of $416 million related to Qatar Idd El Shargi North Dome (ISND) and ISSD proved properties and inventory. The fair value of the proved properties was measured based on the income approach, which 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, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk-adjusted discount rate of 10%. These inputs are categorized as Level 3 in the fair-value hierarchy.

Also in 2018, the marketing and midstream segment incurred approximately $100 million of charges primarily for lower of cost or market adjustments on its crude inventory and line fill.

In 2017, Occidental recorded net impairment and related charges of $397 million related to proved and unproved non-core Permian acreage and $120 million related to idled marketing and midstream facilities.

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

FAIR VALUES - RECURRING

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

Ø Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1.

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

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

Ø Occidental values debt using market-observable information for debt instruments that are traded on secondary markets. For debt instruments that are not traded, the fair value is determined by interpolating the value based on debt with similar terms and credit risk.

NON-FINANCIAL ASSETS

Occidental uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When Occidental is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows, and the expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates, and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs, and other factors and are consistent with assumptions used in the Company’s business plans and investment decisions.

ACCRUED LIABILITIES - CURRENT

Accrued liabilities - current included accrued payroll, commissions and related expenses of $1.2 billion and $428 million at December 31, 2019, and 2018, respectively. Dividends payable, also included in accrued liabilities - current, were $884 million and $600 million at December 31, 2019, and 2018, respectively. Derivate financial instruments, also included in accrued liabilities - current, were $641 million and $134 million at December 31, 2019, and 2018, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental liabilities 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 environmental remediation liability 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 its environmental remediation liabilities 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 its environmental remediation liabilities and adjusts them as new information becomes available. Occidental records environmental remediation liabilities 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. Presently none of its environmental remediation liabilities 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.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental remediation liabilities and the range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may vary from the initial estimate; (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 its environmental remediation liabilities at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental’s environmental remediation liabilities 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 environmental remediation liabilities 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, 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 obligations changes, Occidental records an adjustment to both the asset retirement obligations 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.

The majority of Occidental’s asset retirement obligations relate to the plugging of wells and the related abandonment of oil and gas properties. Revisions in estimated liabilities during the period primarily relate to liabilities acquired in the Acquisition and include, but are not limited to, changes in estimates of asset retirement costs, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlements.

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 asset retirement obligations for the years ended December 31,:

millions	2019			2018
Beginning balance	$	1,499		$	1,312
Liabilities assumed in the Acquisition	3,344			—
Liabilities incurred – capitalized to PP&E	131			31
Liabilities settled and paid	(200		)	(40		)
Accretion expense	71			67
Acquisitions, dispositions and other	—			(18		)
WES loss of control	(359		)	—
Revisions to previous estimates	147			147
Ending balance (a)	$	4,633		$	1,499

^(a)  The ending balance included $248 million and $75 million related to the current balance of AROs that are included in Accrued Liabilities on the Consolidated Balance Sheets at December 31, 2019 and 2018, respectively.

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 carrying value 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 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 operations. There were no fair value hedges as of and during the years ended December 31, 2019, 2018 and 2017.

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% of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. Occidental discontinues hedge accounting when it determines that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

STOCK-BASED INCENTIVE PLANS

Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more fully described in Note 14 - Stock-Based Incentive Plans. 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 (RSU), cash return on capital employed incentive awards (CROCEI), return on capital employed incentive awards (ROCEI) and return on assets incentive awards (ROAI), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout at the grant date. For total shareholder return incentive awards (TSRI), compensation value is initially measured on the grant date using estimated payout levels derived from a Monte Carlo valuation model. Compensation expense for RSUs, CROCEIs, ROCEIs, ROAIs 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. Dividends accrued on unvested awards are adjusted quarterly for any changes in the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable. All such performance or stock-price-related changes are recognized in periodic compensation expense. The stock-settled portion of these awards is expensed using the initially measured compensation value. The liability resulting from the cash settled portion of these awards and accrued dividends are remeasured at each reporting period.

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, 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 15 - Retirement and Postretirement Benefit Plans, in its financial statements using a December 31 measurement date.

Occidental’s defined benefit pension and postretirement benefit plan obligations are actuarially determined 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 U.S. federal, state and foreign income taxes for continuing operations of approximately $1.7 billion, $1.1 billion and $0.8 billion during the years ended December 31, 2019, 2018 and 2017, respectively. Occidental received refunds of $79 million, $82 million and $768 million during the years ended December 31, 2019, 2018, and 2017, respectively. Occidental also paid production, property and other taxes of approximately $725 million, $505 million and $375 million during the years ended December 31, 2019, 2018 and 2017, respectively, substantially all of which was in the United States. Interest paid totaled $911 million, $383 million and $351 million, net of capitalized interest of $85 million, $46 million and $52 million, for the years 2019, 2018 and 2017, respectively.

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s international oil and gas operations is the U.S. dollar since cash flows are denominated principally in U.S. 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.

INCOME TAXES

Occidental files various U.S. federal, state, and foreign income tax returns. The impact of changes in tax regulations are reflected when enacted. In general, deferred federal, state, and foreign income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Occidental routinely assesses the realizability of its deferred tax assets. If Occidental concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Occidental recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). Occidental uses the flow-through method to account for its investment tax credits. See Note 12 - Income Taxes.

OTHER LOSS CONTINGENCIES

Occidental 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. Occidental or certain of its subsidiaries also are involved in proceedings under CERCLA and similar federal, state, local and international 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 Occidental 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 outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. In Note 10 - Environmental Liabilities and Expenditures, Occidental has disclosed its reserve balances for environmental remediation matters that satisfy this criteria. See Note 11 - Lawsuits, Claims, Commitments and Contingencies.

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS - FUTURE BENEFIT PAYMENTS (Details) $ in Millions	Dec. 31, 2019 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure
Expected contribution to defined benefit pension plans in next fiscal year	$ 179
Estimated future benefit payments
2020	810
2021	113
2022	125
2023	128
2024	124
2025 - 2029	625
Postretirement Benefits
Estimated future benefit payments
2020	73
2021	72
2022	71
2023	70
2024	68
2025 - 2029	$ 321

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS - CORPORATE AND GEOGRAPHIC AREAS (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Information
Property, plant and equipment, net	$ 80,469	$ 31,437	$ 31,174
United States
Segment Information
Property, plant and equipment, net	72,808	23,594	22,863
Total Foreign
Segment Information
Property, plant and equipment, net	7,661	7,843	8,311
United Arab Emirates
Segment Information
Property, plant and equipment, net	3,887	4,051	4,241
Oman
Segment Information
Property, plant and equipment, net	2,115	2,048	1,962
Colombia
Segment Information
Property, plant and equipment, net	1,010	927	807
Qatar
Segment Information
Property, plant and equipment, net	562	741	1,236
Other International
Segment Information
Property, plant and equipment, net	$ 87	$ 76	$ 65

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REVENUE (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Schedule of reconciliation of revenue from customers to total net sales

The following table reconciles revenue from customers to total net sales for the years ended December 31:

millions	2019		2018
Revenue from customers	$	18,674	$	15,560
All other revenues (a)	1,719		2,264
Net sales	$	20,393	$	17,824

^(a) 

Included net marketing derivatives, oil collars and calls and chemical exchange contracts.

Schedule of revenue from customers by segment, product, and geographical area

The following table presents Occidental’s revenue from customers by segment, product and geographical area. The oil and gas segment typically sells its oil, gas and NGL at the lease or concession area. Chemical revenues are shown by geographic area based on the location of the sale. Marketing and midstream revenues are shown by the location of sale.

millions	United States			Middle East			Latin America		Other International		Eliminations			Total
Year ended December 31, 2019
Oil and Gas
Oil	$	8,411		$	2,758		$	683	$	—	$	—		$	11,852
NGL	658			263			—		—		—			921
Gas	424			319			20		—		—			763
Other	(1		)	(5		)	—		—		—			(6		)
Segment total	$	9,492		$	3,335		$	703	$	—	$	—		$	13,530
Chemical	$	3,858		$	—		$	155	$	67	$	—		$	4,080
Marketing and Midstream (a)
Gas processing	$	395		$	351		$	—	$	—	$	—		$	746
WES - Gas processing and pipeline	1,110			—			—		—		—			1,110
Power and other	472			—			—		—		—			472
Segment total	$	1,977		$	351		$	—	$	—	$	—		$	2,328
Eliminations	$	—		$	—		$	—	$	—	$	(1,264	)	$	(1,264	)
Consolidated	$	15,327		$	3,686		$	858	$	67	$	(1,264	)	$	18,674
Year ended December 31, 2018
Oil and Gas
Oil	$	5,125		$	3,405		$	715	$	—	$	—		$	9,245
NGL	430			261			—		—		—			691
Gas	185			294			16		—		—			495
Other	7			3			—		—		—			10
Segment total	$	5,747		$	3,963		$	731	$	—	$	—		$	10,441
Chemical	$	4,363		$	—		$	205	$	80	$	—		$	4,648
Marketing and Midstream
Gas processing	$	557		$	425		$	—	$	—	$	—		$	982
Pipelines	311			—			—		—		—			311
Power and other	108			—			—		—		—			108
Segment total	$	976		$	425		$	—	$	—	$	—		$	1,401
Eliminations	$	—		$	—		$	—	$	—	$	(930	)	$	(930	)
Consolidated	$	11,086		$	4,388		$	936	$	80	$	(930	)	$	15,560

^(a) 

The marketing and midstream segment included revenues from customers from WES from the date of the Acquisition to December 31, 2019. See Note 1 - Summary of Significant Accounting Policies

Transaction price allocated to remaining performance obligations

Revenue expected to be recognized from certain performance obligations that are unsatisfied as of December 31, 2019, is reflected in the table below. Occidental applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations. As a result, the following table represents a small portion of Occidental’s expected future consolidated revenues, as future revenue from the sale of most products and services is dependent on future production or variable customer volume and variable commodity prices for that volume:

millions	Total
2020	$	103
2021	103
2022	7
2023	7
2024	7
Thereafter	53
Total	$	280

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of derivative instruments

Occidental had the following collars and calls outstanding at December 31, 2019:

Collars and Calls, not designated as hedges
2020 Settlement
Three-way collars (oil MMBBL)			128.1
	Volume weighted average price per barrel (Brent oil pricing)
		Ceiling sold price (call)	$	74.16
		Floor purchased price (put)	$	55.00
		Floor sold price (put)	$	45.00
2021 Settlement
Call options sold (oil MMBBL)			127.8
	Volume weighted average price per barrel (Brent oil pricing)
		Ceiling sold price (call)	$	74.16

Occidental had the following outstanding interest rate swaps at December 31, 2019:

millions except percentages			Mandatory	Weighted-Average
Notional Principal Amount		Reference Period	Termination Date	Interest Rate
$	550	September 2016 - 2046	September 2020	6.418	%
$	125	September 2016 - 2046	September 2022	6.835	%
$	100	September 2017 - 2047	September 2020	6.891	%
$	250	September 2017 - 2047	September 2021	6.570	%
$	450	September 2017 - 2047	September 2023	6.445	%

Summary of net sales related to the outstanding commodity derivative instruments

The following table summarizes net long/(short) volumes associated with the outstanding marketing commodity derivatives not designated as hedging instruments as of December 31, 2019, and 2018:

	2019		2018
Oil Commodity Contracts
Volume (MMBBL)	55		61
Natural gas commodity contracts
Volume (Bcf)	(128	)	(142	)

Gross and net fair values of outstanding derivatives

The following table presents the fair values of Occidental’s outstanding derivatives. Fair values are presented at gross amounts below, including when derivatives are subject to netting arrangements, and are presented on a net basis in the Consolidated Balance Sheets.

millions	Fair Value Measurements Using											Total Fair Value
Balance Sheet Classification	Level 1			Level 2			Level 3		Netting (a)
December 31, 2019
Oil Collars and Calls
Other current assets	$	—		$	92		$	—	$	—		$	92
Deferred credits and other liabilities - other	—			(160		)	—		—			(160		)
Marketing Derivatives
Other current assets	945			79			—		(973		)	51
Long-term receivables and other assets, net	4			12			—		(4		)	12
Accrued liabilities	(1,008		)	(44		)	—		973			(79		)
Deferred credits and other liabilities - other	(4		)	(1		)	—		4			(1		)
Interest Rate Swaps
Other current assets	—			5			—		—			5
Long-term receivables and other assets, net	—			5			—		—			5
Accrued liabilities	—			(657		)	—		—			(657		)
Deferred credits and other liabilities - other	—			(776		)	—		—			(776		)
Warrant
Deferred credits and other liabilities - other	—			(107		)	—		—			(107		)
December 31, 2018
Marketing Derivatives
Other current assets	$	2,531		$	110		$	—	$	(2,392	)	$	249
Long-term receivables and other assets, net	5			9			—		(6		)	8
Accrued liabilities	(2,357		)	(101		)	—		2,392			(66		)
Deferred credits and other liabilities - other	(6		)	(2		)	—		6			(2		)

^(a)  These amounts do not include collateral. As of December 31, 2019, $104 million of collateral has been netted against derivative liabilities related to interest rate swaps. Occidental had $65 million and $54 million of initial margin deposited with brokers as of December 31, 2019 and 2018, respectively, related to marketing derivatives.

Schedule of gains and losses on derivatives

The following table presents gains and (losses) related to Occidental’s derivative instruments on the Consolidated Statements of Operations:

millions	December 31,
Income Statement Classification	2019			2018		2017
Oil Collars and Calls
Net sales	$	(107	)	$	—	$	—
Marketing Derivatives
Net sales (a)	1,804			2,254		(138		)
Interest Rate Swaps (Excluding WES)
Gain on interest rate swaps and warrants, net	122			—		—
Interest Rate Swaps (WES)
Gain on interest rate swaps and warrants, net	30			—		—
Warrant
Gain on interest rate swaps and warrants, net	81			—		—

^(a) 

Included derivative and non-derivative marketing activity.

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ACCOUNTING AND DISCLOSURE CHANGES - NARRATIVE (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of stranded tax effects	$ 58

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ENVIRONMENTAL LIABILITIES AND EXPENDITURES (Details)	12 Months Ended
	Dec. 31, 2019
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Minimum period of investigations and cleanup for Comprehensive Environmental Response, Compensation and Liability Act National Priorities List sites	10 years

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INCOME TAXES - DOMESTIC AND FOREIGN COMPONENTS OF INCOME (LOSS) FROM CONTINUING OPERATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Domestic	$ (1,632)	$ 3,431	$ (609)
Foreign	1,818	2,177	1,937
Income from continuing operations before income taxes	$ 186	$ 5,608	$ 1,328

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LEASE COMMITMENTS - OTHER INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Aug. 08, 2019
Lessee, Lease, Description [Line Items]
Operating lease costs	$ 449
Amortization of ROU assets	19
Interest on lease liabilities	2
Total lease cost	953
Short-term lease cost	404
Variable lease cost	162
Operating cash flows	262
Investing cash flows	112
Financing cash flows (a)	19
Finance lease	398	$ 86
Failed Sale-Leaseback
Lessee, Lease, Description [Line Items]
Finance lease	300
Operating expense and cost of sales
Lessee, Lease, Description [Line Items]
Operating lease costs	391
Selling, general and administrative expenses
Lessee, Lease, Description [Line Items]
Operating lease costs	$ 92

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DERIVATIVES - INTEREST-RATE DERIVATIVES (Details) - USD ($)	Dec. 31, 2019	Oct. 31, 2019
Interest Rate Swap, 6.418%
Derivative [Line Items]
Notional Principal Amount	$ 550,000,000
Weighted-Average Interest Rate	6.418%
Interest Rate Swap, 6.835%
Derivative [Line Items]
Notional Principal Amount	$ 125,000,000	$ 125,000,000
Weighted-Average Interest Rate	6.835%
Interest Rate Swap, 6.891%
Derivative [Line Items]
Notional Principal Amount	$ 100,000,000
Weighted-Average Interest Rate	6.891%
Interest Rate Swap, 6.570%
Derivative [Line Items]
Notional Principal Amount	$ 250,000,000
Weighted-Average Interest Rate	6.57%
Interest Rate Swap, 6.445%
Derivative [Line Items]
Notional Principal Amount	$ 450,000,000
Weighted-Average Interest Rate	6.445%

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INVENTORIES (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Inventory Disclosure [Abstract]
Net carrying value of inventories valued under the LIFO method	$ 168	$ 169
Raw materials	75	74
Materials and supplies	879	445
Commodity inventory and finished goods	533	788
Inventories	1,487	1,307
Revaluation to LIFO	(40)	(47)
Total	$ 1,447	$ 1,260

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LEASE COMMITMENTS - NARRATIVE (Details) - USD ($) $ in Millions	Dec. 31, 2019	Aug. 08, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Operating lease assets	$ 1,385
Lease liability	1,423	$ 488
Finance lease	398	86
Offshore And Onshore Drilling Rigs
Lessee, Lease, Description [Line Items]
Operating lease assets	217
Compressors
Lessee, Lease, Description [Line Items]
Operating lease assets	162
Other Field Equipment
Lessee, Lease, Description [Line Items]
Operating lease assets	$ 389
Oil And Gas Exploration And Development Equipment | Low end of range
Lessee, Lease, Description [Line Items]
Contract expiration term	2 years
Oil And Gas Exploration And Development Equipment | High end of range
Lessee, Lease, Description [Line Items]
Contract expiration term	9 years
Pipelines, Rail Cars, Storage Facilities, Easements And Real Estate
Lessee, Lease, Description [Line Items]
Operating lease assets	$ 659
Real Estate Leases | Low end of range
Lessee, Lease, Description [Line Items]
Contract expiration term	1 year
Real Estate Leases | High end of range
Lessee, Lease, Description [Line Items]
Contract expiration term	14 years
Oil And Gas Exploration And Development Equipment, Restate Offices, Compressors, And Field Equipment [Member]
Lessee, Lease, Description [Line Items]
Finance lease	$ 398
Anadarko Petroleum Corporation
Lessee, Lease, Description [Line Items]
Operating lease assets		503
Lease liability		$ 574
Accounting Standards Update 2016-02
Lessee, Lease, Description [Line Items]
Operating lease assets			$ 772

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DERIVATIVES - GAINS AND LOSSES ON DERIVATIVES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ 233	$ 0	$ 0
Oil Collars and Calls | Net sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	(107)	0	0
Marketing Derivatives | Net sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	1,804	2,254	(138)
Interest Rate Swaps | Gain (Loss) on Interest Rate Swaps and Warrants, Net
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	122	0	0
Interest Rate Swaps | Gain (Loss) on Interest Rate Swaps and Warrants, Net | WES
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	30	0	0
Warrant | Gain (Loss) on Interest Rate Swaps and Warrants, Net
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ 81	$ 0	$ 0

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INVENTORIES

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

INVENTORIES

NOTE 6 - INVENTORIES

Finished goods primarily represents oil, which is carried at the lower of weighted-average cost or net realizable value, and caustic soda and chlorine, which are valued under the LIFO method. Net carrying values of inventories valued under the LIFO method were $168 million and $169 million at December 31, 2019 and 2018, respectively. Inventories consisted of the following at December 31:

millions	2019			2018
Raw materials	$	75		$	74
Materials and supplies	879			445
Commodity inventory and finished goods	533			788
	1,487			1,307
Revaluation to LIFO	(40		)	(47		)
Total	$	1,447		$	1,260

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ACCOUNTING AND DISCLOSURE CHANGES

12 Months Ended

Dec. 31, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

ACCOUNTING AND DISCLOSURE CHANGES

NOTE 2 - ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

In January 2019, Occidental adopted the new lease standard Accounting Standards Codification Topic 842 - Leases (ASC 842). The new standard requires Occidental to recognize most leases, including operating leases, on the balance sheet. The new rules require lessees to recognize a right-of-use (ROU) asset and lease liability for all leases with lease terms of more than 12 months. Occidental adopted the standard using the modified retrospective approach, including adopting several optional practical expedients. See Note 8 - Lease Commitments.

In February 2018, the Financial Accounting Standards Board (FASB) released standards that allow the reclassification from accumulated other comprehensive income to retained earnings of stranded tax effects resulting from changes to U.S. federal tax law from the 2017 Tax Cuts and Jobs Act (Tax Reform) enacted in December 2017. Occidental early adopted this standard in the first quarter of 2018, resulting in the reclassification of $58 million in stranded tax effects from accumulated other comprehensive income (AOCI) to retained earnings.

In January 2018, Occidental adopted the new revenue recognition standard Topic 606 - Revenue from Contracts with Customers and related updates (ASC 606). The new standard requires more detailed disclosures related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Occidental adopted the standard using the modified retrospective method. The cumulative-effect adjustment to retained earnings upon adoption was not material. See Note 5 - Revenue.

In January 2017, FASB issued new guidance clarifying the definition of a business under the topic Business Combinations. The rules became effective in the first quarter of 2018, and did not have a material impact to Occidental’s financial statements upon adoption.

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ENVIRONMENTAL LIABILITIES AND EXPENDITURES

12 Months Ended

Dec. 31, 2019

Environmental Remediation Obligations [Abstract]

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

NOTE 10 - ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state, local and international laws and regulations related to improving or maintaining environmental quality. The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and international 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, 2019, Occidental participated in or monitored remedial activities or proceedings at 177 sites, which included 36 sites assumed through the Acquisition. The following table presents Occidental’s current and non-current environmental remediation liabilities as of December 31, 2019 and 2018, the current portion of which is included in accrued liabilities ($162 million in 2019 and $120 million in 2018) and the remainder in deferred credits and other liabilities - environmental remediation liabilities ($1.04 billion in 2019 and $762 million in 2018). Occidental continues to evaluate the remediation obligations assumed through the Acquisition.

Occidental’s environmental remediation sites are grouped into four categories: NPL sites listed or proposed for listing by the EPA on the CERCLA NPL and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

	2019			2018
millions, except number of sites	Number of Sites	Remediation Balance		Number of Sites	Remediation Balance
NPL sites	36	$	463	34	$	458
Third-party sites	74	311		68	168
Occidental-operated sites	17	154		14	115
Closed or non-operated Occidental sites	50	269		29	141
Total	177	$	1,197	145	$	882

As of December 31, 2019, Occidental’s environmental liabilities exceeded $10 million each at 20 of the 177 sites described above, and 101 of the sites had liabilities from $0 to $1 million each. As of December 31, 2019, 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 — accounted for 94 percent of its liabilities associated with NPL sites. Seventeen of the 36 NPL sites are indemnified by Maxus.

Six of the 74 third-party sites — a Maxus-indemnified chrome site in New Jersey, a former copper mining and smelting operation in Tennessee, a former oil field, a landfill and a chemical plant in California, and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities — accounted for 75 percent of Occidental’s liabilities associated with these sites. Nine of the 74 third-party sites are indemnified by Maxus.

Five sites — oil and gas operations in Colorado and chemical plants in Kansas, Louisiana, New York and Texas — accounted for 67 percent of the liabilities associated with the Occidental-operated sites.

Six other sites — a landfill in Western New York, a former refinery in Oklahoma, former chemical plants in California, Tennessee and Washington, and a closed coal mine in Pennsylvania — accounted for 64 percent of the liabilities associated with closed or non-operated Occidental sites.

Environmental remediation liabilities vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation. Occidental recorded environmental remediation expenses of $112 million, $47 million and $39 million for the years ended December 31, 2019, 2018 and 2017, respectively. Environmental remediation expenses primarily relate to changes to existing conditions from past operations. Based on current estimates, Occidental expects to expend funds corresponding to approximately 40 percent of the year-end remediation balance over the next three to four years with the remainder over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those amounts currently recorded for environmental remediation for all of its environmental sites could be up to $1.1 billion.

MAXUS ENVIRONMENTAL SITES

When Occidental acquired Diamond Shamrock Chemicals Company (DSCC) in 1986, Maxus, 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.

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 remediation liability 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 accrued estimated environmental remediation liability does not consider any recoveries for indemnified costs. Occidental’s ultimate share of the estimated costs may be higher or lower than its accrued remediation liability, and is subject to final design plans and the resolution 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. In June 2018, Occidental filed a complaint under CERCLA in Federal District Court in the State of New Jersey against numerous potentially responsible parties for reimbursement of amounts incurred or to be incurred to comply with the AOC, the ROD or to perform other remediation activities at the Site.

In June 2017, the court overseeing the Maxus bankruptcy approved a Plan of Liquidation (Plan) to liquidate Maxus and create a trust to pursue claims against YPF, Repsol and others to satisfy claims by Occidental and other creditors for past and future cleanup and other costs. In July 2017, the court-approved Plan became final and the trust became effective. Among other responsibilities, the trust will pursue claims against YPF, Repsol and others and distribute assets to Maxus’ creditors in accordance with the trust agreement and Plan. In June 2018, the trust filed its complaint against YPF and Repsol in Delaware bankruptcy court asserting claims based upon, among other things, fraudulent transfer and alter ego. On February 15, 2019, the bankruptcy court denied Repsol’s and YPF’s motions to dismiss the complaint.

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Summary of Revenues, Costs and Assets Held for Sale of Discontinued Operations

The following table presents the amounts reported in discontinued operations, net of income taxes, related to the Africa Assets subsequent to the Acquisition closing date through December 31, 2019:

millions	2019
Revenues and other income
Net sales	$	739
Costs and other deductions
Oil and gas lease operating expense	$	81
Transportation expense	14
Taxes other than on income	133
Fair value adjustment on assets held for sale	244
Other	53
Total costs and other deductions	$	525
Income before income taxes	$	214
Income tax expense	(229		)
Discontinued operations, net of tax	$	(15	)

The following table presents amounts related to the Africa Assets reported as held for sale in the Consolidated Balance Sheet as of December 31, 2019:

millions	2019
Current assets	$	289
Property, plant and equipment, net	5,481
Long-term receivables and other assets, net	256
Assets held for sale (a)	$	6,026
Current liabilities	$	452
Long-term debt, net - finance leases	185
Deferred income taxes	1,112
Asset retirement obligations	181
Other	80
Liabilities of assets held for sale (a)	$	2,010
Net assets held for sale	$	4,016

^(a)  Assets and liabilities held for sale at December 31, 2019 included South Africa assets which were sold to Total in January 2020.

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LEASE COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Schedule of operating lease maturities

At December 31, 2019, Occidental’s leases expire based on the following schedule:

millions	Operating Leases(a)			Finance Leases(b)			Total
2020	$	555		$	53		$	608
2021	408			45			453
2022	136			41			177
2023	99			37			136
2024	81			34			115
Thereafter	254			275			529
Total lease payments	1,533			485			2,018
Less: Interest	(110		)	(87		)	(197		)
Total lease liabilities	$	1,423		$	398		$	1,821

^(a)  The weighted-average remaining lease term is 4.6 years and the weighted-average discount rate is 2.53%.

^(b) 

The weighted-average remaining lease term is 11.6 years and the weighted-average discount rate is 3.74%.

The following table reconciles the undiscounted cash flows related to the operating and finance lease liabilities assumed in the Acquisition and recorded on the Consolidated Balance Sheet at the Acquisition date:

millions	Operating Leases			Finance Leases			Total
2019	$	90		$	7		$	97
2020	172			17			189
2021	64			16			80
2022	42			13			55
2023	28			8			36
Thereafter	136			43			179
Total lease payments	$	532		$	104		$	636
Less: Interest	(44		)	(18		)	(62		)
Total lease liabilities (a)	$	488		$	86		$	574

^(a) 

Excluded operating and finance leases associated with the Africa Assets of $74 million and $201 million, respectively.

Schedule of finance lease maturities

At December 31, 2019, Occidental’s leases expire based on the following schedule:

millions	Operating Leases(a)			Finance Leases(b)			Total
2020	$	555		$	53		$	608
2021	408			45			453
2022	136			41			177
2023	99			37			136
2024	81			34			115
Thereafter	254			275			529
Total lease payments	1,533			485			2,018
Less: Interest	(110		)	(87		)	(197		)
Total lease liabilities	$	1,423		$	398		$	1,821

^(a)  The weighted-average remaining lease term is 4.6 years and the weighted-average discount rate is 2.53%.

^(b) 

The weighted-average remaining lease term is 11.6 years and the weighted-average discount rate is 3.74%.

The following table reconciles the undiscounted cash flows related to the operating and finance lease liabilities assumed in the Acquisition and recorded on the Consolidated Balance Sheet at the Acquisition date:

millions	Operating Leases			Finance Leases			Total
2019	$	90		$	7		$	97
2020	172			17			189
2021	64			16			80
2022	42			13			55
2023	28			8			36
Thereafter	136			43			179
Total lease payments	$	532		$	104		$	636
Less: Interest	(44		)	(18		)	(62		)
Total lease liabilities (a)	$	488		$	86		$	574

^(a) 

Excluded operating and finance leases associated with the Africa Assets of $74 million and $201 million, respectively.

Schedule of lease related assets and liabilities

The following table presents lease balances and their location on the Consolidated Balance Sheet at December 31, 2019:

millions	Balance sheet location	2019
Assets:
Operating	Operating lease assets	$	1,385
Finance	Property, plant and equipment	397
Total lease assets		$	1,782
Liabilities:
Current
Operating	Current operating lease liabilities	$	569
Finance	Current maturities of long-term debt	51
Non-current
Operating	Deferred credits and other liabilities - Operating lease liabilities	854
Finance	Long-term debt, net	347
Total lease liabilities		$	1,821

Schedule of future net minimum lease payments for noncancelable operating leases

At December 31, 2018, future undiscounted net minimum fixed lease payments for non-cancellable operating leases, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows:

millions	Operating Leases
2019	$	186
2020	147
2021	96
2022	68
2023	49
Thereafter	158
Total minimum lease payments(a)	$	704

^(a)  The amount represents the future undiscounted cash flows at December 31, 2018, excluding any amount associated with the Acquisition.

Schedule of lease costs

The following tables present Occidental’s total lease cost and classifications, as well as cash paid for amounts included in the measurement of operating and finance lease liabilities:

millions	Year ended December 31, 2019
Lease cost classification(a)
Operating lease costs(b)
Property, plant and equipment, net		$	449
Operating expense and cost of sales		391
Selling, general and administrative expenses		92
Finance lease cost
Amortization of ROU assets		19
Interest on lease liabilities		2
Total lease cost		$	953

^(a)  Amounts reflected are gross before joint-interest recoveries.

^(b)  Included short-term lease cost of $404 million for the twelve months ended December 31, 2019, and variable lease cost of $162 million for the twelve months ended December 31, 2019.

millions	Year ended December 31, 2019
Operating cash flows		$	262
Investing cash flows		$	112
Financing cash flows (a)		$	19

^(a) 

Excludes cash received of approximately $300 million associated with the failed sale-leaseback, see Note 4 - Acquisitions, Dispositions and Other.

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS - FAIR VALUE OF PENSION PLAN ASSETS (Details) - Pension Benefits - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 1,639	$ 338	$ 403
U.S. government securities
Defined Benefit Plan Disclosure
Fair value of plan assets	13	17
Corporate bonds
Defined Benefit Plan Disclosure
Fair value of plan assets	60	66
Common/collective trusts
Defined Benefit Plan Disclosure
Fair value of plan assets		9
Bond funds
Defined Benefit Plan Disclosure
Fair value of plan assets	46	31
Blend funds
Defined Benefit Plan Disclosure
Fair value of plan assets		48
International funds
Defined Benefit Plan Disclosure
Fair value of plan assets	68
Common and preferred stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	173	141
Other
Defined Benefit Plan Disclosure
Fair value of plan assets	29	31
Net Payables
Defined Benefit Plan Disclosure
Fair value of plan assets	3	5
Total pensions plan assets
Defined Benefit Plan Disclosure
Fair value of plan assets	1,642	343
Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure
Fair value of plan assets	389
Level 1
Defined Benefit Plan Disclosure
Fair value of plan assets	300
Level 1 | U.S. government securities
Defined Benefit Plan Disclosure
Fair value of plan assets	13	17
Level 1 | Corporate bonds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 1 | Common/collective trusts
Defined Benefit Plan Disclosure
Fair value of plan assets		0
Level 1 | Bond funds
Defined Benefit Plan Disclosure
Fair value of plan assets	46	31
Level 1 | Blend funds
Defined Benefit Plan Disclosure
Fair value of plan assets		48
Level 1 | International funds
Defined Benefit Plan Disclosure
Fair value of plan assets	68
Level 1 | Common and preferred stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	173	141
Level 1 | Other
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 1 | Total pensions plan assets
Defined Benefit Plan Disclosure
Fair value of plan assets	300	237
Level 2
Defined Benefit Plan Disclosure
Fair value of plan assets	89
Level 2 | U.S. government securities
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | Corporate bonds
Defined Benefit Plan Disclosure
Fair value of plan assets	60	66
Level 2 | Common/collective trusts
Defined Benefit Plan Disclosure
Fair value of plan assets		9
Level 2 | Bond funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | Blend funds
Defined Benefit Plan Disclosure
Fair value of plan assets		0
Level 2 | International funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0
Level 2 | Common and preferred stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | Other
Defined Benefit Plan Disclosure
Fair value of plan assets	29	31
Level 2 | Total pensions plan assets
Defined Benefit Plan Disclosure
Fair value of plan assets	89	106
Level 3
Defined Benefit Plan Disclosure
Fair value of plan assets	0
Level 3 | U.S. government securities
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | Corporate bonds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | Common/collective trusts
Defined Benefit Plan Disclosure
Fair value of plan assets		0
Level 3 | Bond funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | Blend funds
Defined Benefit Plan Disclosure
Fair value of plan assets		0
Level 3 | International funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0
Level 3 | Common and preferred stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | Other
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | Total pensions plan assets
Defined Benefit Plan Disclosure
Fair value of plan assets	0	$ 0
Investments measured at net asset value
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 1,253

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS - RESULTS OF OPERATIONS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) segment	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting [Abstract]
Number of operating segments | segment	3
Segment Information
Net sales	$ 20,393	$ 17,824	$ 12,508
Income (loss) from continuing operations before income taxes	186	5,608	1,328
Income tax expense	(693)	(1,477)	(17)
Income (loss) from continuing operations	(507)	4,131	1,311
INVESTMENTS IN UNCONSOLIDATED ENTITIES	6,389	1,680	1,515
Property, plant and equipment additions	6,441	5,020	3,651
Depreciation, depletion and amortization	5,981	3,977	4,002
Total assets	109,330	43,854	42,026
Pre-tax impairment and related charges on domestic undeveloped leases	285
Impairments of assets	285
Employee severance and related costs	1,000
Crucial seismic data	401
Bank, legal and consulting fees	213
Tax effect of pre-tax adjustments	(245)	198	(392)
Qatar ISND and ISSD
Segment Information
Impairments of assets		416
Marketing and Midstream
Segment Information
Impairments of assets		100
Marketing and Midstream | Non Core Midstream Assets
Segment Information
Pre-tax net gain from divestiture		907
Operating segments | Oil and Gas
Segment Information
Net sales	13,423	10,441	7,870
Income (loss) from continuing operations before income taxes	2,352	2,442	1,111
Income tax expense	0	0	0
Income (loss) from continuing operations	2,352	2,442	1,111
INVESTMENTS IN UNCONSOLIDATED ENTITIES	181	0	0
Property, plant and equipment additions	5,559	4,443	2,968
Depreciation, depletion and amortization	4,994	3,254	3,269
Total assets	77,936	24,874	23,595
Gain on sale	475
Impairment charges	285
Pre-tax impairment and related charges on domestic undeveloped leases	39
Operating segments | Oil and Gas | South Texas and non-core acreage in the Permian basin
Segment Information
Pre-tax gain on sale of properties			655
Operating segments | Oil and Gas | Non-core Permian acreage
Segment Information
Impairment charges			397
Operating segments | Chemical
Segment Information
Net sales	4,102	4,657	4,355
Income (loss) from continuing operations before income taxes	799	1,159	822
Income tax expense	0	0	0
Income (loss) from continuing operations	799	1,159	822
INVESTMENTS IN UNCONSOLIDATED ENTITIES	689	733	771
Property, plant and equipment additions	272	277	323
Depreciation, depletion and amortization	368	354	352
Total assets	4,361	4,359	4,364
Operating segments | Marketing and Midstream
Segment Information
Net sales	4,132	3,656	1,157
Income (loss) from continuing operations before income taxes	241	2,802	85
Income tax expense	0	0	0
Income (loss) from continuing operations	241	2,802	85
INVESTMENTS IN UNCONSOLIDATED ENTITIES	5,519	947	739
Property, plant and equipment additions	475	221	296
Depreciation, depletion and amortization	563	331	340
Total assets	17,055	11,087	11,775
Charge upon loss of control	1,000
Gain on sale of equity investment	114
Impairment charges			120
Operating segments | Marketing and Midstream | Interest Rate Swaps
Segment Information
Mark to market gain on interest rate swap	30
Corporate and Eliminations
Segment Information
Net sales	(1,264)	(930)	(874)
Income (loss) from continuing operations before income taxes	(3,206)	(795)	(690)
Income tax expense	(693)	(1,477)	(17)
Income (loss) from continuing operations	(3,899)	(2,272)	(707)
INVESTMENTS IN UNCONSOLIDATED ENTITIES	0	0	5
Property, plant and equipment additions	135	79	64
Depreciation, depletion and amortization	56	38	41
Total assets	$ 9,978	$ 3,534	$ 2,292

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Trade receivables, reserves	$ 19	$ 21
Preferred stock, par value (in dollars per share)	$ 1.00
Preferred stock, shares outstanding (in shares)	100,000	0
Common stock, per share par value (in dollars per share)	$ 0.20	$ 0.20
Common stock, authorized shares (in shares)	1,100,000,000	1,100,000,000
Common stock, issued shares (in shares)	1,044,434,893	895,115,637
Treasury stock, shares (in shares)	150,323,151	145,726,051

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Consolidated Statements of Stockholders' Equity - USD ($) $ in Millions	Total	Preferred Stock	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Non-controlling Interests
Balance at Dec. 31, 2016	$ 21,497	$ 0	$ 178	$ (9,143)	$ 7,747	$ 22,981	$ (266)	$ 0
Increase (Decrease) in Stockholders' Equity
Net income (loss)	1,311					1,311
Other comprehensive income (loss), net of tax	8						8
Dividends on common stock	(2,357)					(2,357)
Issuance of common stock and other, net	138		1		137
Purchases of treasury stock	(25)			(25)
Balance at Dec. 31, 2017	20,572	0	179	(9,168)	7,884	21,935	(258)	0
Increase (Decrease) in Stockholders' Equity
Net income (loss)	4,131					4,131
Other comprehensive income (loss), net of tax	144						144
Dividends on common stock	(2,374)					(2,374)
Issuance of common stock and other, net	162				162
Purchases of treasury stock	(1,305)			(1,305)
Reclassification of stranded tax effects						58	(58)
Balance at Dec. 31, 2018	21,330	0	179	(10,473)	8,046	23,750	(172)	0
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(522)					(667)		145
Other comprehensive income (loss), net of tax	(49)						(49)
Dividends on common stock	(2,585)					(2,585)
Dividends on preferred stock	(318)					(318)
Issuance of common stock and other, net	6,939		30		6,909
Issuance of preferred stock	9,762	9,762
Purchases of treasury stock	(180)			(180)
Fair value of noncontrolling interest acquired	4,895							4,895
Noncontrolling interest distributions, net	(131)							(131)
Change in control WES	(4,909)							(4,909)
Balance at Dec. 31, 2019	$ 34,232	$ 9,762	$ 209	$ (10,653)	$ 14,955	$ 20,180	$ (221)	$ 0

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

NOTE 18 - INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental conducts its operations through three segments: (1) oil and gas; (2) chemical; and (3) marketing and midstream.

Income taxes, interest income, interest expense, environmental remediation expenses, Anadarko acquisition-related costs and unallocated corporate expenses are included under Corporate and Eliminations. 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.

millions	Oil and Gas			Chemical		Marketing and Midstream			Corporate and Eliminations				Total
Year ended December 31, 2019
Net sales	$	13,423		$	4,102	$	4,132		$	(1,264	)		$	20,393
Income (loss) from continuing operations before income taxes	$	2,352	(a)	$	799	$	241	(b)	$	(3,206	)	(c)	$	186
Income tax expense	—			—		—			(693		)	(d)	(693		)
Income (loss) from continuing operations	$	2,352		$	799	$	241		$	(3,899	)		$	(507	)
Investments in unconsolidated entities	$	181		$	689	$	5,519		$	—			$	6,389
Property, plant and equipment additions(e)	$	5,559		$	272	$	475		$	135			$	6,441
Depreciation, depletion and amortization	$	4,994		$	368	$	563		$	56			$	5,981
Total assets	$	77,936		$	4,361	$	17,055		$	9,978			$	109,330
Year ended December 31, 2018
Net sales	$	10,441		$	4,657	$	3,656		$	(930	)		$	17,824
Income (loss) from continuing operations before income taxes	$	2,442	(a)	$	1,159	$	2,802	(b)	$	(795	)	(c)	$	5,608
Income tax expense	—			—		—			(1,477		)	(d)	(1,477		)
Income (loss) from continuing operations	$	2,442		$	1,159	$	2,802		$	(2,272	)		$	4,131
Investments in unconsolidated entities	$	—		$	733	$	947		$	—			$	1,680
Property, plant and equipment additions(e)	$	4,443		$	277	$	221		$	79			$	5,020
Depreciation, depletion and amortization	$	3,254		$	354	$	331		$	38			$	3,977
Total assets	$	24,874		$	4,359	$	11,087		$	3,534			$	43,854
Year ended December 31, 2017
Net sales	$	7,870		$	4,355	$	1,157		$	(874	)		$	12,508
Income (loss) from continuing operations before income taxes	$	1,111	(a)	$	822	$	85	(b)	$	(690	)	(c)	$	1,328
Income tax expense	—			—		—			(17		)	(d)	(17		)
Income (loss) from continuing operations	$	1,111		$	822	$	85		$	(707	)		$	1,311
Investments in unconsolidated entities	$	—		$	771	$	739		$	5			$	1,515
Property, plant and equipment additions(e)	$	2,968		$	323	$	296		$	64			$	3,651
Depreciation, depletion and amortization	$	3,269		$	352	$	340		$	41			$	4,002
Total assets	$	23,595		$	4,364	$	11,775		$	2,292			$	42,026

^(a)  The 2019 amount included a net gain on sale of $475 million related to Occidental’s joint venture with Ecopetrol in the Midland Basin and sale of real estate assets, a $285 million impairment charge associated with domestic undeveloped leases that were set to expire in the near term, where Occidental had no plans to pursue exploration activities, and a $39 million charge related to Occidental’s mutually agreed early termination of its Qatar ISSD contract. The 2018 amount included $416 million for the impairment of proved oil properties and inventory in Qatar ISND and ISSD due to the decline in oil prices. The 2017 amount included pre-tax asset sale gains of $655 million primarily related to South Texas and non-core acreage in the Permian basin and $397 million for the impairment of non-core proved and unproved Permian acreage.

^(b)  The 2019 amount included a $1 billion charge as a result of recording Occidental’s investment in WES at fair value as of December 31, 2019 upon the loss of control, a $114 million gain on the sale of an equity investment in Plains and a $30 million mark-to-market gain on an interest rate swap for WES. The 2018 amount included pre-tax asset sale gains of $907 million on the sale of non-core domestic midstream assets. The 2017 amount included pre-tax charges of $120 million related to asset impairments of idled facilities.

^(c)  The 2019 amount included corporate transactions related to the Acquisition including charges of $1.0 billion related to employee severance and related costs, $401 million related to crucial seismic data and $213 million for bank, legal and consulting fees. There were no significant corporate transactions and events affecting 2018 and 2017 results. The tax effect of these pre-tax adjustments was a $245 million benefit in 2019, and $198 million expense and $392 million expense in 2018 and 2017, respectively.

^(d)  Included all foreign and domestic income taxes from continuing operations.

^(e)  Included capital expenditures and capitalized interest, but excluded acquisition and disposition of assets.

GEOGRAPHIC AREAS

	Property, plant and equipment, net
millions	2019		2018		2017
United States	$	72,808	$	23,594	$	22,863
International
United Arab Emirates	3,887		4,051		4,241
Oman	2,115		2,048		1,962
Colombia	1,010		927		807
Qatar	562		741		1,236
Other International	87		76		65
Total International	7,661		7,843		8,311
Total	$	80,469	$	31,437	$	31,174

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STOCK-BASED INCENTIVE PLANS

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

STOCK-BASED INCENTIVE PLANS

NOTE 14 - STOCK-BASED INCENTIVE PLANS

Occidental issues stock-based awards to employees in accordance with the terms of the shareholder approved 2015 Long-Term Incentive Plan (2015 LTIP). An aggregate of 80 million shares of Occidental common stock were authorized for issuance and approximately 6.6 million shares had been allocated to employee awards through December 31, 2019. As of December 31, 2019, approximately 52.5 million shares were available for grants of future awards. The plan requires each share covered by an award (other than 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 52.5 million depending on the type of award granted, and shares available for future awards may increase by the number of shares that are forfeited, canceled, or correspond to the portion of any stock-based awards settled in cash, including awards that were issued under a previous plan that remain outstanding. Current outstanding awards include RSUs, stock options, CROCEIs, and TSRIs.

During 2019, non-employee directors were granted awards for 41,752 shares of 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.

For the year ended December 31, 2019, Occidental incurred expenses of $208 million related to stock-based incentive plans, of which $31 million was related to the Acquisition. For the years ended December 31, 2018, and 2017, expense related to stock-based incentive plans was $180 million, and $150 million, respectively. The income tax benefit associated with this expense was $43 million, $47 million, and $32 million in the years ended December 31, 2019, 2018, and 2017, respectively.

As of December 31, 2019, unrecognized compensation expense for all unvested stock-based incentive awards was $354.1 million. This expense is expected to be recognized over a weighted-average period of 1.9 years. Occidental accounts for forfeitures as they occur.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs may be settled in stock or may be cash settled liabilities. These awards vest from one to 4 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 RSUs, dividend equivalents are paid during the vesting period.

CASH-SETTLED LIABILITY AWARDS

The weighted-average, grant-date fair values of cash-settled RSUs granted in 2019, 2018 and 2017 were $42.62, $75.86, and $66.62 per share, respectively. Cash-Settled RSUs resulted in payments of $4 million, $18 million, and $23 million, during the years ended December 31, 2019, 2018 and 2017, respectively.

STOCK-SETTLED EQUITY AWARDS

The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2019, 2018, and 2017 were $58.73, $69.87, and $67.21, respectively. The fair value of RSUs settled in shares during the years ended December 31, 2019, 2018 and 2017 was $148 million, $109 million, and $64 million, respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2019, is presented below:

	Cash-Settled					Stock-Settled
thousands, except fair values	RSUs		Weighted-Average Grant-Date Fair Value			RSUs		Weighted-Average Grant-Date Fair Value
Unvested at January 1	186			$	73.93	3,971			$	73.19
Granted (a)	4,267			$	42.62	3,543			$	58.73
Vested	(67	)		$	72.26	(2,743	)		$	67.04
Forfeitures	(39	)		$	47.60	(376	)		$	67.25
Unvested at December 31	4,347			$	43.46	4,395			$	65.88

^(a)  Included 1.5 million shares issued in exchange for Anadarko stock-based incentive shares.

TSRIs

Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date. Payout is based upon Occidental’s absolute total shareholder return and performance relative to its peers. TSRIs have payouts that range from 0% to 200% of the target award and settle in stock once certified. Dividend equivalents for TSRIs are accumulated and paid upon certification of the award. The fair value of TSRIs settled in shares during the years ended December 31, 2019, 2018 and 2017 was $4 million, $12 million, and $5 million, 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 (U.S. 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
	2019			2018			2017
Assumptions used:
Risk-free interest rate	2.5		%	2.3		%	1.5		%
Volatility factor	22		%	24		%	25		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	67.19		$	69.87		$	67.21

A summary of Occidental’s unvested TSRIs as of December 31, 2019 and changes during the year ended December 31, 2019 is presented below:

	TSRIs
thousands, except fair values	Awards		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	1,444			$	70.97
Granted	578			$	67.19
Vested (a)	(442	)		$	76.83
Forfeitures	(43	)		$	76.83
Unvested at December 31	1,537			$	67.70

^(a)  Presented at the target payouts. The weighted-average payout at vesting was 19% of the target, resulting in the issuance of approximately 83,000 shares of Occidental common stock.

STOCK OPTIONS

Certain employees have been granted options that are settled in stock. Exercise prices of the options were equal to the quoted market value of Occidental’s stock on the grant date. No options were granted, vested or forfeited in 2019. The intrinsic value of options exercised during the years ended December 31, 2019, 2018, and 2017 was insignificant. As of December 31, 2019, there were 530,000 fully vested options outstanding with an exercise price of $79.98 per share and a remaining life of 2.1 years.

CROCEI, ROCEI and ROAI

Certain executives are awarded CROCEI, ROCEI or ROAI awards that vest at the end of a three-year period if performance targets based on cash return on capital employed, return on capital employed, or return on assets are certified as being met. These awards are settled in stock upon certification of the performance target, with payouts that range from 0% to 200% of the target award. Dividend equivalents are accumulated and paid upon certification of the award.

	CROCEI, ROCEI, and ROAI
thousands, except fair values	Awards		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	210			$	71.60
Granted	81			$	67.19
Vested (a)	(137	)		$	72.54
Forfeited	—			—
Unvested at December 31	154			$	68.44

^(a) 

Presented at the target payouts. The weighted-average payout at vesting was 86% of the target resulting in the issuance of approximately 118,000 shares.

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Components of amounts recognized in the consolidated balance sheets

The following tables show the amounts recognized in Occidental’s consolidated balance sheets at December 31, 2019 and 2018, related to its pension and postretirement benefit plans:

	Pension Benefits						Postretirement Benefits
millions	2019			2018			2019			2018
Amounts recognized in the consolidated balance sheet:
Long-term receivables and other assets, net	$	85		$	60		$	—		$	—
Accrued liabilities	(96		)	(25		)	(72		)	(45		)
Deferred credits and other liabilities — pension and postretirement obligations	(704		)	(46		)	(1,103		)	(763		)
	$	(715	)	$	(11	)	$	(1,175	)	$	(808	)
Accumulated other comprehensive loss included the following after-tax balances:
Net (gain) loss	$	(25	)	$	91		$	184		$	151
Prior service credit	—			—			(67		)	(72		)
	$	(25	)	$	91		$	117		$	79

Funding status of Occidental's plans

The following tables show the funding status, obligations and plan asset fair values of Occidental related to its pension and postretirement benefit plans for the years ended December 31:

	Pension Benefits						Postretirement Benefits
millions	2019			2018			2019			2018
Changes in the benefit obligation:
Benefit obligation — beginning of year	$	349		$	391		$	808		$	999
Service cost — benefits earned during the period	45			5			24			23
Interest cost on projected benefit obligation	39			15			36			34
Actuarial (gain) loss	(33		)	(19		)	45			(90		)
Foreign currency exchange rate gain	—			(3		)	—			—
Curtailment (gain) loss	(136		)	—			10			—
Special termination benefits	49			—			—			—
Benefits paid	(95		)	(40		)	(51		)	(57		)
Participant contributions	—			—			2			—
Plan amendments	—			—			—			(101		)
Additions due to the Acquisition	2,136			—			301			—
Benefit obligation — end of year	$	2,354		$	349		$	1,175		$	808
Changes in plan assets:
Fair value of plan assets — beginning of year	$	338		$	403		$	—		$	—
Actual return on plan assets	122			(33		)	—			—
Participant contributions	—			—			2			—
Employer contributions	41			8			49			—
Benefits paid	(95		)	(40		)	(51		)	—
Additions due to the Acquisition	1,233			—			—			—
Fair value of plan assets — end of year	$	1,639		$	338		$	—		$	—
Unfunded status:	$	(715	)	$	(11	)	$	(1,175	)	$	(808	)

Schedule of projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with an accumulated benefit obligation in excess of plan assets and plan assets in excess of the accumulated benefit obligation

The following table sets forth details of the obligations and assets of Occidental’s defined benefit pension plans for the years December 31:

	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
millions	2019		2018		2019		2018
Projected benefit obligation	$	2,175	$	173	$	179	$	176
Accumulated benefit obligation	$	1,918	$	169	$	179	$	176
Fair value of plan assets	$	1,375	$	98	$	264	$	240

Components of the net periodic benefit costs

The following table sets forth the components of net periodic benefit costs for the years ended December 31:

	Pension Benefits									Postretirement Benefits
millions	2019			2018			2017			2019			2018			2017
Net periodic benefit costs:
Service cost — benefits earned during the period	$	45		$	5		$	6		$	24		$	23		$	21
Interest cost on projected benefit obligation	39			15			17			36			34			38
Expected return on plan assets	(50		)	(25		)	(24		)	—			—			—
Recognized actuarial loss	9			7			10			8			14			14
Recognized prior service credit	—			—			—			(8		)	—			—
Liability (gain) loss due to curtailment	(91		)	—			—			6			—			—
Special termination benefits	49			—			—			—			—			—
Other costs and adjustments	(2		)	1			3			—			(2		)	1
Net periodic benefit cost	$	(1	)	$	3		$	12		$	66		$	69		$	74

Weighted-average assumptions used to determine Occidental's benefit obligation and net periodic benefit cost for domestic plans

The following table sets forth the weighted-average assumptions used to determine Occidental’s benefit obligation and net periodic benefit cost for domestic plans for the years ended December 31:

	Pension Benefits				Postretirement Benefits
	2019		2018		2019		2018
Benefit Obligation Assumptions:
Discount rate	3.10	%	4.09	%	3.26	%	4.29	%
Net Periodic Benefit Cost Assumptions:
Discount rate for January 1 - August 31 expense	3.21	%	3.45	%	3.41	%	3.61	%
Discount rate for September 1 - December 31 expense	3.21	%	3.45	%	3.41	%	4.14	%
Assumed long-term rate of return on assets	6.50	%	6.50	%	—		—
Rates of increase in compensation levels	5.44	%	—		—		—

Fair values of Occidental's pension plan assets by asset category

The fair values of Occidental’s pension plan assets by asset category were as follows:

millions	Level 1		Level 2		Level 3		Total
December 31, 2019
Asset Class:
U.S. government securities	$	13	$	—	$	—	$	13
Corporate bonds (a)	—		60		—		60
Mutual funds:
Bond funds	46		—		—		46
International funds	68		—		—		68
Common and preferred stocks (b)	173		—		—		173
Other	—		29		—		29
Investments measured at fair value	$	300	$	89	$	—	$	389
Investments measured at net asset value (c)	—		—		—		1,253
Total pension plan assets (d)	$	300	$	89	$	—	$	1,642
December 31, 2018
Asset Class:
U.S. government securities	$	17	$	—	$	—	$	17
Corporate bonds (a)	—		66		—		66
Common/collective trusts (e)	—		9		—		9
Mutual funds:
Bond funds	31		—		—		31
Blend funds	48		—		—		48
Common and preferred stocks (b)	141		—		—		141
Other	—		31		—		31
Total pension plan assets (d)	$	237	$	106	$	—	$	343

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

^(b)  This category included 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)  Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.

^(e) 

Amounts exclude net payables of approximately $3 million and $5 million as of December 31, 2019 and 2018, respectively.

Estimated future benefit payments, which reflect expected future service, as appropriate

Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows for the years ended December 31:

millions	Pension Benefits		Postretirement Benefits
2020	$	810		$	73
2021	$	113		$	72
2022	$	125		$	71
2023	$	128		$	70
2024	$	124		$	68
2025 - 2029	$	625		$	321

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - NATURE OF OPERATIONS, WES INVESTMENT AND DISCONTINUED OPERATIONS (Details) $ in Millions		5 Months Ended	12 Months Ended
	Aug. 08, 2019 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2019 USD ($) segment	Sep. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
NATURE OF OPERATIONS
Number of reportable segments | segment			3
Summary of significant accounting policies
Equity method investment amounts		$ 6,389	$ 6,389		$ 1,680	$ 1,515
Mozambique LNG Assets | Disposed of by sale
Summary of significant accounting policies
Sale consideration				$ 4,200
WES
Summary of significant accounting policies
Equity method investment amounts		5,128	5,128
Charge recorded as a result of loss of control			1,000
Anadarko Petroleum Corporation
Summary of significant accounting policies
Revenues from date of the Acquisition		4,200
Equity method investment amounts		2,800	$ 2,800
Anadarko Petroleum Corporation | Africa Assets | Assets held for sale
Summary of significant accounting policies
Sale consideration	$ 8,800
WES | Anadarko Petroleum Corporation
Summary of significant accounting policies
Revenues from date of the Acquisition		1,100
Expenses from date of the Acquisition		500
Operating cash flows from date of the Acquisition		498
WES Operating
Summary of significant accounting policies
Non-voting general partner unit interest			2.00%
WES
Summary of significant accounting policies
Limited partner interest			55.40%
Non-voting general partner unit interest			2.00%
Limited partner unit interest			54.50%
Total effective economic interest in WES			56.30%
Pro rata share of net assets		1,900	$ 1,900
Tax basis difference		$ 3,200	$ 3,200
WES
Summary of significant accounting policies
Percentage of unaffiliated unitholders			20.00%
WES | Occidental
Summary of significant accounting policies
Voting percentage for certain unitholder matters, limit			45.00%
Limited partner units percentage			40.00%
Transfer of limited partner interest, percentage			2.00%
Economic interest to general partner, percentage			2.00%
WES | WES Operating
Summary of significant accounting policies
Limited partner interest	98.00%
Public Ownership | WES | WES
Summary of significant accounting policies
Limited partner interest			44.60%

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STOCK-BASED INCENTIVE PLANS (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-Based Payment Award
Aggregate number of shares authorized for issuance (in shares)	80,000,000
Number of shares awarded to date (in shares)	6,600,000
Number of shares counted for each share covered by an award in determining the number of shares that are available for future awards	3
Certain stock-based incentive amounts
Compensation expense	$ 208.0	$ 180.0	$ 150.0
Income tax benefit recognized in the income statement	43.0	$ 47.0	$ 32.0
Unrecognized compensation expense	$ 354.1
Weighted-average period over which unrecognized compensation expense is expected to be recognized	1 year 10 months 24 days
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Issued (in shares)	3,188,000	1,628,000	1,252,000
Anadarko Petroleum Corporation
Certain stock-based incentive amounts
Compensation expense	$ 31.0
High end of range
Share-based Compensation Arrangement by Share-Based Payment Award
Maximum shares available for future issuance (in shares)	52,500,000
Common Stock | Non-employee directors
Share-based Compensation Arrangement by Share-Based Payment Award
Restricted stock granted to non-employee directors (in shares)	41,752
RSUs
Stock-Based Awards
Forfeiture of RSUs	7 years
RSUs | Low end of range
Certain stock-based incentive amounts
Award vesting period	1 year
RSUs | High end of range
Certain stock-based incentive amounts
Award vesting period	4 years
Cash-Settled RSUs
Certain stock-based incentive amounts
Cash paid	$ 4.0	$ 18.0	$ 23.0
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	186,000
Granted (in shares)	4,267,000
Vested (in shares)	(67,000)
Forfeitures (in shares)	(39,000)
Unvested, end of period (in shares)	4,347,000	186,000
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Unvested, beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 73.93
Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)	42.62	$ 75.86	$ 66.62
Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)	72.26
Forfeitures, Weighted-Average Grant-Date Fair Value (in dollars per share)	47.60
Unvested, end of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 43.46	$ 73.93
Shares issued in exchange for Anadarko stock based incentive shares (in shares)	1,500,000
Vested (in shares)	67,000
Stock-Settled RSUs
Certain stock-based incentive amounts
Fair value of shares vested during the year	$ 148.0	$ 109.0	$ 64.0
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	3,971,000
Granted (in shares)	3,543,000
Vested (in shares)	(2,743,000)
Forfeitures (in shares)	(376,000)
Unvested, end of period (in shares)	4,395,000	3,971,000
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Unvested, beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 73.19
Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)	58.73	$ 69.87	$ 67.21
Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)	67.04
Forfeitures, Weighted-Average Grant-Date Fair Value (in dollars per share)	67.25
Unvested, end of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 65.88	$ 73.19
Vested (in shares)	2,743,000
TSRIs
Certain stock-based incentive amounts
Award vesting period	3 years
Fair value of shares vested during the year	$ 4.0	$ 12.0	$ 5.0
Grant-date assumptions used in the Monte Carlo simulation models
Risk-free interest rate (as a percent)	2.50%	2.30%	1.50%
Volatility factor (as a percent)	22.00%	24.00%	25.00%
Expected life (years)	3 years	3 years	3 years
Grant-date fair value of underlying Occidental common stock (in dollars per share)	$ 67.19	$ 69.87	$ 67.21
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	1,444,000
Granted (in shares)	578,000
Vested (in shares)	(442,000)
Forfeitures (in shares)	(43,000)
Unvested, end of period (in shares)	1,537,000	1,444,000
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Unvested, beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 70.97
Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)	67.19
Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)	76.83
Forfeitures, Weighted-Average Grant-Date Fair Value (in dollars per share)	76.83
Unvested, end of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 67.70	$ 70.97
Payouts for performance-based awards granted (as a percent)	19.00%
Issued (in shares)	83,000
Vested (in shares)	442,000
TSRIs | Low end of range
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Payouts for performance-based awards granted (as a percent)	0.00%
TSRIs | High end of range
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Payouts for performance-based awards granted (as a percent)	200.00%
Options
Stock-Based Awards
Awards granted (in shares)	0
Awards vested (in shares)	0
Awards forfeited (in shares)	0
Option and SAR transactions
Option and SAR transactions
Fully vested options (in shares)	530,000
Exercise price (in dollars per share)	$ 79.98
Remaining life of options	2 years 1 month 6 days
ROCEI/ROAI
Certain stock-based incentive amounts
Award vesting period	3 years
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	210,000
Granted (in shares)	81,000
Vested (in shares)	(137,000)
Forfeitures (in shares)	0
Unvested, end of period (in shares)	154,000	210,000
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Unvested, beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 71.60
Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)	67.19
Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)	72.54
Forfeitures, Weighted-Average Grant-Date Fair Value (in dollars per share)	0
Unvested, end of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$ 68.44	$ 71.60
Vested (in shares)	137,000
ROCEI/ROAI | 52% of the target
Roll-forward of stock awards other than options and SARS.
Vested (in shares)	(118,000)
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Payout at vesting percentage	86.00%
Vested (in shares)	118,000
ROCEI/ROAI | Low end of range
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Payouts for performance-based awards granted (as a percent)	0.00%
ROCEI/ROAI | High end of range
Stock awards other than options and SARs, Weighted-Average Grant-Date Fair Value (in dollars per share)
Payouts for performance-based awards granted (as a percent)	200.00%

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS - SUMMARY OF ASSETS HELD FOR SALE (Details) - Anadarko's Africa Assets - Disposed of by sale $ in Millions	Dec. 31, 2019 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current assets	$ 289
Property, plant and equipment, net	5,481
Long-term receivables and other assets, net	256
Assets held for sale	6,026
Current liabilities	452
Long-term debt, net - finance leases	185
Deferred income taxes	1,112
Asset retirement obligations	181
Other	80
Liabilities of assets held for sale	2,010
Net assets held for sale	$ 4,016

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THE ACQUISITION - PRO FORMA INFORMATION (Details) - Anadarko Petroleum Corporation - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Revenues	$ 28,723	$ 31,206
Net income (loss) attributable to common stockholders	$ (769)	$ 2,965
Net income (loss) attributable to common stockholders per share—basic (usd per share)	$ (0.95)	$ 3.26
Net income (loss) attributable to common stockholders per share—diluted (usd per share)	$ (0.95)	$ 3.25
Net income (loss) attributable to common stockholders excluding pro-forma results of WES	$ (1,100)	$ 2,800

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INCOME TAXES - COMPONENTS OF DEFERRED TAX ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities
Property, plant and equipment differences	$ (12,375)	$ (2,089)
Equity investments, partnerships and foreign subsidiaries	(989)	(161)
Gross long-term deferred tax liabilities	(13,364)	(2,250)
Deferred tax assets
Environmental reserves	261	195
Postretirement benefit accruals	441	176
Deferred compensation and benefits	266	170
Asset retirement obligations	906	280
Foreign tax credit carryforwards	4,379	2,356
General business credit carryforwards	443	429
Net operating loss carryforward	692	29
Interest expense carryforward	492	0
All other	782	111
Gross long-term deferred tax assets	8,662	3,746
Valuation allowance	(4,959)	(2,403)
Net long-term deferred tax assets	3,703	1,343
Less: Foreign deferred tax asset in long-term receivables and other assets, net	(56)	0
Total deferred income taxes, net	$ (9,717)	$ (907)

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REVENUE - SCHEDULE OF EXPECTED FUTURE REVENUE (Details) $ in Millions	Dec. 31, 2019 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 103
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 103
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 7
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 7
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 7
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 280
Remaining performance obligation, period

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS - ASSUMPTIONS (Details) - USD ($) $ in Millions	4 Months Ended		8 Months Ended		12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Aug. 31, 2019	Aug. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Benefit Obligation Assumptions:
Discount rate	3.10%	4.09%			3.10%	4.09%
Net Periodic Benefit Cost Assumptions:
Discount rate	3.21%	3.45%	3.21%	3.45%
Assumed long-term rate of return on assets					6.50%	6.50%
Average rate of increase in compensation levels (as a percent)					5.44%	0.00%
Net decrease in pension plan obligations					$ 15
Postretirement Benefits
Benefit Obligation Assumptions:
Discount rate	3.26%	4.29%			3.26%	4.29%
Net Periodic Benefit Cost Assumptions:
Discount rate	3.41%	4.14%	3.41%	3.61%
Assumed long-term rate of return on assets					0.00%	0.00%
Average rate of increase in compensation levels (as a percent)					0.00%	0.00%
Net decrease in postretirement plan obligations					$ 9
Effect of 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates
Effect of 1-percent increase in assumed healthcare cost trend rates on postretirement benefit obligation					131
Effect of 1-percent decrease in assumed healthcare cost trend rates on postretirement benefit obligation					103
Effect of 1-percent increase in assumed healthcare cost trend rate on annual service and interest costs					13
Effect of 1-percent decrease in assumed healthcare cost trend rate on annual service and interest costs					$ 9
Postretirement Benefits | MAPD
Assumed healthcare cost trend rates
Projected annual rates of healthcare cost trend rates, year two (as a percent)	9.60%				9.60%
Projected annual rates of healthcare cost trend rates, year nine and beyond (as a percent)	4.50%				4.50%
Postretirement Benefits | MAPD | Low end of range
Assumed healthcare cost trend rates
Health care cost trend rates for current year (as a percent)	4.30%				4.30%
Projected annual rates of healthcare cost trend rates, next fiscal year (as a percent)	(7.70%)				(7.70%)
Postretirement Benefits | MAPD | High end of range
Assumed healthcare cost trend rates
Health care cost trend rates for current year (as a percent)	21.50%				21.50%
Projected annual rates of healthcare cost trend rates, next fiscal year (as a percent)	(6.20%)				(6.20%)
Postretirement Benefits | Non-MAPD
Assumed healthcare cost trend rates
Projected annual rates of healthcare cost trend rates, year nine and beyond (as a percent)	4.50%				4.50%
Postretirement Benefits | Non-MAPD | Low end of range
Assumed healthcare cost trend rates
Health care cost trend rates for current year (as a percent)	6.70%				6.70%
Postretirement Benefits | Non-MAPD | High end of range
Assumed healthcare cost trend rates
Health care cost trend rates for current year (as a percent)	7.50%				7.50%
Foreign | Low end of range
Net Periodic Benefit Cost Assumptions:
Discount rate					1.00%	1.00%
Average rate of increase in compensation levels (as a percent)					1.00%
Foreign | High end of range
Net Periodic Benefit Cost Assumptions:
Discount rate					8.80%	8.90%
Average rate of increase in compensation levels (as a percent)					8.00%