Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, 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, 2018, 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 21, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

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.

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

/s/ KPMG LLP

Houston, Texas

February 21, 2019

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, 2018, 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, 2018, 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, 2018 and 2017, 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, 2018, and the related notes and financial statement schedule II - valuation and qualifying accounts (collectively, “the consolidated financial statements”), and our report dated February 21, 2019 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 21, 2019

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

Assets at December 31,		2018				2017
CURRENT ASSETS
Cash and cash equivalents		$	3,033			$	1,672
Trade receivables, net of reserves of $21 in 2018 and $16 in 2017		4,893				4,145
Inventories		1,260				1,246
Assets held for sale		—				474
Other current assets		746				733
Total current assets		9,932				8,270
INVESTMENTS
Investment in unconsolidated entities		1,680				1,515
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment		58,799				53,409
Chemical segment		7,001				6,847
Midstream and marketing segment		8,070				9,493
Corporate		550				497
		74,420				70,246
Accumulated depreciation, depletion and amortization		(42,983		)		(39,072		)
		31,437				31,174
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET		805				1,067
TOTAL ASSETS		$	43,854			$	42,026

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

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

Liabilities and Stockholders’ Equity at December 31,		2018				2017
CURRENT LIABILITIES
Current maturities of long-term debt		$	116			$	500
Accounts payable		4,885				4,408
Accrued liabilities		2,411				2,492
Total current liabilities		7,412				7,400
LONG-TERM DEBT, NET		10,201				9,328
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes, net		907				581
Asset retirement obligations		1,424				1,241
Pension and postretirement obligations		809				1,005
Environmental remediation reserves		762				728
Other		1,009				1,171
		4,911				4,726
STOCKHOLDERS' EQUITY
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, issued shares: 2018 — 895,115,637 and 2017 — 893,468,707		179				179
Treasury stock: 2018 — 145,726,051 shares and 2017 — 128,364,195 shares		(10,473		)		(9,168		)
Additional paid-in capital		8,046				7,884
Retained earnings		23,750				21,935
Accumulated other comprehensive loss		(172		)		(258		)
Total stockholders' equity		21,330				20,572
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	43,854			$	42,026

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

Consolidated Statements of Operations	Occidental Petroleum Corporation and Subsidiaries
(in millions, except per-share amounts)

For the years ended December 31,		2018				2017				2016
REVENUES AND OTHER INCOME
Net sales		$	17,824			$	12,508			$	10,090
Interest, dividends and other income		136				99				106
Gains on sale of equity investments and other assets		974				667				202
		18,934				13,274				10,398
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion, and amortization of $3,976 in 2018, $4,000 in 2017, and $4,266 in 2016)		6,568				5,594				5,189
Selling, general and administrative and other operating expenses		1,613				1,424				1,330
Taxes other than on income		439				311				277
Depreciation, depletion and amortization		3,977				4,002				4,268
Asset impairments and related items		561				545				825
Exploration expense		110				82				62
Interest and debt expense, net		389				345				292
		13,657				12,303				12,243
INCOME (LOSS) BEFORE INCOME TAXES AND OTHER ITEMS		5,277				971				(1,845		)
(Provision for) benefit from domestic and foreign income taxes		(1,477		)		(17		)		662
Income from equity investments		331				357				181
INCOME (LOSS) FROM CONTINUING OPERATIONS		4,131				1,311				(1,002		)
Income from discontinued operations		—				—				428
NET INCOME (LOSS)		$	4,131			$	1,311			$	(574	)
BASIC EARNINGS (LOSS) PER COMMON SHARE (attributable to common stock)
Income (loss) from continuing operations		$	5.40			$	1.71			$	(1.31	)
Discontinued operations, net		—				—				0.56
BASIC EARNINGS (LOSS) PER COMMON SHARE		$	5.40			$	1.71			$	(0.75	)
DILUTED EARNINGS (LOSS) PER COMMON SHARE (attributable to common stock)
Income (loss) from continuing operations		$	5.39			$	1.70			$	(1.31	)
Discontinued operations, net		—				—				0.56
DILUTED EARNINGS (LOSS) PER COMMON SHARE		$	5.39			$	1.70			$	(0.75	)
The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Comprehensive Income	Occidental Petroleum Corporation and Subsidiaries
(in millions)

For the years ended December 31,		2018				2017				2016
Net income (loss) attributable to common stock		$	4,131			$	1,311			$	(574	)
Other comprehensive income (loss) items:
Foreign currency translation gains		—				3				—
Unrealized gains (losses) on derivatives (a)		(6		)		13				(14		)
Pension and postretirement gains (losses) (b)		137				(7		)		47
Reclassification of realized losses (gains) on derivatives (c)		13				(1		)		8
Other comprehensive income, net of tax		144				8				41
Comprehensive income (loss)		$	4,275			$	1,319			$	(533	)

(a)	Net of tax of $2, $(7) and $8 in 2018, 2017 and 2016, respectively.

(b)	Net of tax of $(38), $4 and $(26) in 2018, 2017 and 2016, respectively. See Note 14 for additional information.

(c)	Net of tax of $(4), $0 and $(4) in 2018, 2017 and 2016, respectively.

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

Consolidated Statements of Stockholders' Equity	Occidental Petroleum Corporation and Subsidiaries
(in millions)

		Equity Attributable to Common Stock
		Common Stock				Treasury Stock				Additional Paid-in Capital				Retained Earnings				Accumulated Other Comprehensive Loss				Total Equity
Balance, December 31, 2015		$	178			$	(9,121	)		$	7,640			$	25,960			$	(307	)		$	24,350
Net loss		—				—				—				(574		)		—				(574		)
Other comprehensive income, net of tax		—				—				—				—				41				41
Dividends on common stock		—				—				—				(2,405		)		—				(2,405		)
Issuance of common stock and other, net		—				—				107				—				—				107
Purchases of treasury stock		—				(22		)		—				—				—				(22		)
Balance, December 31, 2016		$	178			$	(9,143	)		$	7,747			$	22,981			$	(266	)		$	21,497
Net income		—				—				—				1,311				—				1,311
Other comprehensive income, net of tax		—				—				—				—				8				8
Dividends on common stock		—				—				—				(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		—				—				—				(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 3)		—				—				—				58				(58		)		—
Balance, December 31, 2018		$	179			$	(10,473	)		$	8,046			$	23,750			$	(172	)		$	21,330

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

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

For the years ended December 31,		2018				2017				2016
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)		$	4,131			$	1,311			$	(574	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Income from discontinued operations		—				—				(428		)
Depreciation, depletion and amortization of assets		3,977				4,002				4,268
Deferred income tax (benefit) provision		371				(719		)		(517		)
Other noncash charges to income		34				219				116
Asset impairments and related items		561				545				665
Gain on sales of equity investments and other assets, net		(974		)		(667		)		(202		)
Undistributed earnings from equity investments		(43		)		(68		)		3
Dry hole expenses		56				51				33
Changes in operating assets and liabilities:
Increase in receivables		(740		)		(158		)		(1,091		)
Decrease (increase) in inventories		(108		)		(349		)		17
Decrease in other current assets		94				39				65
(Decrease) increase in accounts payable and accrued liabilities		195				(89		)		609
Increase in current domestic and foreign income taxes		38				64				17
Other operating, net		77				680				(461		)
Operating cash flow from continuing operations		7,669				4,861				2,520
Operating cash flow from discontinued operations, net of taxes		—				—				864
Net cash provided by operating activities		7,669				4,861				3,384
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(4,975		)		(3,599		)		(2,717		)
Change in capital accrual		55				122				(114		)
Payments for purchases of assets and businesses		(928		)		(1,064		)		(2,044		)
Sales of equity investments and assets, net		2,824				1,403				302
Other, net		(182		)		59				(170		)
Net cash used by investing activities		(3,206		)		(3,079		)		(4,743		)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt, net		978				—				4,203
Payments of long-term debt		(500		)		—				(2,710		)
Proceeds from issuance of common stock		33				28				36
Purchases of treasury stock		(1,248		)		(25		)		(22		)
Cash dividends paid		(2,374		)		(2,346		)		(2,309		)
Other, net		9				—				—
Net cash used by financing activities		(3,102		)		(2,343		)		(802		)
Increase (decrease) in cash, cash equivalents, and restricted cash		1,361				(561		)		(2,161		)
Cash, cash equivalents, and restricted cash — beginning of year		1,672				2,233				4,394
Cash and cash equivalents — end of year		$	3,033			$	1,672			$	2,233

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

Notes to Consolidated Financial Statements	Occidental Petroleum Corporation and Subsidiaries

NOTE 1	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

In this report, "Occidental" means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental conducts its operations through various subsidiaries and affiliates. Occidental's principal businesses consist of three segments. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing 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. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.

PRINCIPLES OF CONSOLIDATION

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

Certain financial statements, notes and supplementary data for prior years have been reclassified to conform to the 2018 presentation.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) are accounted for under the equity method. Occidental reviews equity-method investments for impairment whenever events or changes in circumstances indicate that an other-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

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 $8.9 billion as of December 31, 2018, and net sales of approximately $5.3 billion for the year ended December 31, 2018, 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

Cash equivalents are short-term, highly liquid investments that are readily convertible to cash. Cash equivalents were approximately $2.6 billion and $1.3 billion at December 31, 2018, and 2017, respectively. In the year ended December 31, 2016, restricted cash, which was the result of the separation of California Resources, was used to retire debt and pay dividends. There was no restricted cash as of December 31, 2016, or thereafter.

RECEIVABLES AND OTHER CURRENT ASSETS

Trade receivables, net, of $4.9 billion and $4.1 billion at December 31, 2018, and 2017, 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 includes 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. Otherwise, Occidental charges the costs of the related wells to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Occidental generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

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

in millions		2018				2017				2016
Balance — Beginning of Year		$	108			$	56			$	76
Additions to capitalized exploratory well costs pending the determination of proved reserves		220				201				29
Reclassifications to property, plant and equipment based on the determination of proved reserves		(198		)		(128		)		(28		)
Capitalized exploratory well costs charged to expense		(18		)		(21		)		(21		)
Balance — End of Year		$	112			$	108			$	56

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 has no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.

Occidental performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to declines in current and forward prices, significant changes in reserve estimates, changes in management's plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows. 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 16 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 $1.0 billion at both December 31, 2018, and 2017. The unproved amounts are not subject to DD&A until they are classified as proved properties. Capitalized costs attributable to the properties become subject to DD&A when proved reserves are assigned to the property. If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results.

Chemical

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

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

Midstream and Marketing

Occidental’s midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, using either the unit-of-production or straight-line method.

Occidental performs impairment tests on its midstream and marketing assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

IMPAIRMENTS AND RELATED ITEMS

Due to the decline in crude oil prices in late 2018, management performed an impairment test of its proved oil and gas properties. Occidental's oil and gas segment recorded impairment and related charges of $416 million related to Qatar Idd El Shargi North Dome (ISND) and Idd El Shargi South Dome (ISSD) proved properties and inventory. In Oman, while undiscounted estimated future cash flows exceeded net book value, future declines in cash flows could result in a future impairment. At December 31, 2018, Occidental's net proved properties balance in Qatar ISND and ISSD and Oman were $149 million and $1.7 billion, respectively.

Also in 2018, the midstream and marketing 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 midstream and marketing facilities.

In 2016, Occidental's oil and gas segment recorded net impairment and related charges of $46 million related to the exit from Libya, Iraq and non-core domestic areas, as well as commodity price declines. The Midstream segment recorded charges related to the termination of crude oil supply contracts at a cost of $160 million. Other impairments of $619 million included costs related to the California Resources spin-off and an allowance for doubtful accounts related to environmental sites indemnified by Maxus described in Note 9. Occidental recorded a reserve against this receivable due to the uncertainty of collection as a result of the Maxus bankruptcy.

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

Ø

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

Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar asset or liability. This approach utilizes management's judgments regarding expectations of projected cash flows, and discounts those cash flows using a risk-adjusted discount rate.

ACCRUED LIABILITIES - CURRENT

Accrued liabilities - current include accrued payroll, commissions and related expenses of $428 million and $412 million at December 31, 2018, and 2017, respectively. Dividend payable, also included in accrued liabilities - current, were $600 million and $598 million at December 31, 2018, and 2017, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental reserves and related charges and expenses for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable and the costs can be reasonably estimated. In determining the reserves and the range of reasonably possible additional losses, Occidental refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. Occidental bases environmental reserves on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective. Occidental periodically reviews reserves and adjusts them as new information becomes available. Occidental records environmental reserves on a discounted basis when it deems the aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established. The reserve methodology with respect to discounting for a specific site is not modified once it is established. Presently none of the environmental reserves 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 reserves and range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements may occur.

Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (1) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible parties; (2) oil and gas ventures in which each participant pays its proportionate share

of remediation costs reflecting its working interest; or (3) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, Occidental evaluates the financial viability of the other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to Occidental of their failure to participate when estimating Occidental's ultimate share of liability. Occidental records reserves at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

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

ASSET RETIREMENT OBLIGATIONS

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

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning. Occidental does not know or cannot estimate when it may settle these obligations. Therefore, Occidental cannot reasonably estimate the fair value of these liabilities. Occidental will recognize these conditional asset retirement obligations in the periods in which sufficient information becomes available to reasonably estimate their fair values.

The following table summarizes the activity of the asset retirement obligations, of which $1.4 billion and $1.2 billion is included in deferred credits and other liabilities - asset retirement obligations as of December 31, 2018 and 2017, respectively, with the remaining current portion in accrued liabilities.

For the years ended December 31, (in millions)		2018				2017
Beginning balance		$	1,312			$	1,369
Liabilities incurred – capitalized to PP&E		31				46
Liabilities settled and paid		(40		)		(39		)
Accretion expense		67				67
Acquisitions, dispositions and other – changes in PP&E		(18		)		(136		)
Revisions to estimated cash flows – changes in PP&E		147				5
Ending balance		$	1,499			$	1,312

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of 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, 2018, 2017 and 2016.

A hedge is regarded as highly effective such that it qualifies for hedge accounting if, at inception and throughout its life, it is expected that changes in the fair value or cash flows of the hedged item will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. Occidental discontinues hedge accounting when it determines that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

STOCK-BASED INCENTIVE PLANS

Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more fully described in Note 13. 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.

EARNINGS PER SHARE

Occidental's instruments containing rights to nonforfeitable dividends granted in stock-based awards are considered participating securities prior to vesting and, therefore, have been deducted from earnings in computing basic and diluted EPS under the two-class method.

Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the weighted-average number of common shares outstanding during each period, net of treasury shares and including vested but unissued shares and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options and unvested stock awards.

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans, which are more fully described in Note 14, in its financial statements using a December 31 measurement date.

Occidental determines its defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. Occidental estimates the rate of return on assets with regard to current market factors but within the context of historical returns. Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.

Pension and any postretirement plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common and collective trusts are valued at the fund units' net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market. Short-term investment funds are valued at the fund units' NAV provided by the issuer.

SUPPLEMENTAL CASH FLOW INFORMATION

Occidental paid United States federal, state and foreign income taxes for continuing operations of approximately $1.1 billion, $0.8 billion and $0.6 billion during the years ended December 31, 2018, 2017 and 2016, respectively. Occidental received refunds of $82 million, $768 million and $325 million during the years ended December 31, 2018, 2017, and 2016, respectively. Occidental also paid production, property and other taxes of approximately $505 million, $375 million and $345 million during the years ended December 31, 2018, 2017 and 2016, respectively, substantially all of which was in the United States. Interest paid totaled $383 million, $351 million and $312 million, net of capitalized interest of $46 million, $52 million and $64 million, for the years 2018, 2017 and 2016, 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.

NOTE 2	ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

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.

In March 2018, Occidental issued $1.0 billion of 4.2-percent senior notes due 2048. Occidental received net proceeds of approximately $985 million. Interest on the notes is payable semi-annually in arrears in March and September of each year, beginning on September 15, 2018. The proceeds were used to refinance the repayment of the $500 million aggregate principal amount of Occidental's 1.5-percent senior notes due in February 2018, with the remainder used for general corporate purposes.

In January 2018, Occidental entered into a five-year,$3.0 billion revolving credit facility (2018 Credit Facility), replacing the previous credit facility that was scheduled to expire in August 2019. The 2018 Credit Facility has similar terms to the previous credit facility and does not contain material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow under the facility.

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.

2016

In 2016, Occidental completed its exit of non-core operations in Bahrain, Iraq, Libya and Yemen.

In November 2016, Occidental issued $1.5 billion of senior notes, comprised of $750 million of 3.0-percent senior notes due 2027 and $750 million of 4.1-percent senior notes due 2047. Occidental received net proceeds of $1.49 billion. Interest on the senior notes is payable semi-annually in arrears in February and August each year for each series of senior notes beginning August 15, 2017. Occidental used the proceeds for general corporate purposes.

In October 2016, Occidental acquired producing and non-producing leasehold acreage in the Permian Basin. This acquisition included 35,000 net acres in Reeves and Pecos counties, Texas, in the Southern Delaware Basin, in areas where Occidental currently operates or has working interests. Separately, Occidental also acquired working interests in several producing oil and gas CO2 floods and related EOR infrastructure, increasing Occidental's ownership in several properties where it is currently the operator or an existing working interest partner. The total purchase price for these transactions was approximately $2.0 billion which was allocated between unproved and proved property.

In September 2016, Occidental completed the sale of its South Texas Eagle Ford non-operated properties for $63 million resulting in a pre-tax gain of $59 million.

In August 2016, Occidental terminated crude oil supply contracts at a cost of $160 million.

In the second quarter of 2016, Occidental received $330 million as final payment from the settlement with the Republic of Ecuador. In January 2016, Occidental reached an understanding on the terms of payment for the approximate $1.0 billion payable to Occidental by the Republic of Ecuador under a November 2015 International Center for Settlement of Investment Disputes arbitration award. This award relates to Ecuador's 2006 expropriation of the oil and gas segment's Participation Contract for Block 15. Occidental recorded a pre-tax gain of $681 million in 2016. The results related to Ecuador were presented as discontinued operations.

In May and June 2016, respectively, Occidental utilized part of the proceeds from the April 2016 senior notes offering (described below) to exercise the early redemption option on $1.25 billion of 1.75-percent senior notes due in the first quarter of 2017 and to retire all $750 million of 4.125-percent senior notes that matured in June 2016.

In April 2016, Occidental issued $2.75 billion of senior notes, comprised of $400 million of 2.6-percent senior notes due 2022, $1.15 billion of 3.4-percent senior notes due 2026 and $1.2 billion of 4.4-percent senior notes due 2046. Occidental received net proceeds of approximately $2.72 billion. Interest on the senior notes is payable semi-annually in arrears in April and October of each year for each series of senior notes, beginning on October 15, 2016. Occidental used a portion of the proceeds to retire debt in May and June 2016, and used the remaining proceeds for general corporate purposes.

In March 2016, Occidental distributed its remaining shares of California Resources Corporation (California Resources) through a special stock dividend to stockholders of record as of February 29, 2016. Upon distribution, Occidental recorded a $78 million loss to reduce the investment to its fair market value, and Occidental no longer owns any shares of California Resources common stock.

In March 2016, Occidental completed the sale of its Piceance Basin operations in Colorado for $153 million resulting in a pre-tax gain of $121 million. The assets and liabilities related to these operations were presented as held for sale at December 31, 2015, and primarily included property, plant and equipment and current accrued liabilities and asset retirement obligations.

In February 2016, Occidental repaid $700 million of 2.5-percent senior notes that matured.

In January 2016, Occidental completed the sale of its Occidental Tower building in Dallas, Texas, for net proceeds of approximately $85 million, resulting in a pre-tax gain of $57 million. The building was classified as held for sale as of December 31, 2015.

NOTE 3	ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

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 4 Revenue.

In March 2017, FASB issued guidance related to presentation of net periodic pension cost and net periodic postretirement benefit cost. The rules became effective in the first quarter of 2018. These rules did not have a material impact to Occidental's financial statements upon adoption.

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.

In November 2016, FASB issued new guidance related to the cash flow classification and presentation of the changes in restricted cash on the statement of cash flows. The rules were effective for the interim and annual periods beginning after December 15, 2017 and were applied retrospectively. Occidental did not have restricted cash as of December 31, 2018, 2017 or 2016. Total of cash and restricted cash was $4.4 billion as of December 31, 2015. In the statement of cash flows for the year ended December 31, 2016, the $1.2 billion previously presented as cash flows from financing activities related to the decrease in restricted cash was retrospectively applied to the beginning balance of cash, cash equivalents, and restricted cash at December 31, 2015. As a result, cash flows from financing activities for the year ended December 31, 2016 decreased by $1.2 billion and the beginning balance of cash, cash equivalents, and restricted cash was increased by the same amount. The cash balance as of December 31, 2016 was unaffected.

In August 2016, FASB issued new guidance related to the classification of certain cash receipts and payments on the statement of cash flows. The rules were effective for the interim and annual periods beginning after December 15, 2017. The rules resulted in the retrospective reclassification of $135 million of cash flows related to corporate owned life insurance policies from operating to investing cash flows for the years ended December 31, 2017.

RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

In February 2016, FASB issued rules which require Occidental to recognize most leases, including operating leases, on the balance sheet. The new rules require lessees to recognize a right-of-use asset and lease liability for all leases with lease terms of more than 12 months. The lease liability represents the discounted obligation to make future minimum lease payments. The corresponding right-of-use asset includes the discounted obligation in addition to any upfront payment or cost incurred during contract execution of the lease. Recognition, measurement and disclosure of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. Occidental will apply the revised lease rules for its interim and annual reporting periods starting January 1, 2019, using a modified retrospective approach, including adopting several optional practical expedients affecting both leases that commenced before and after the effective date. Generally, Occidental is the lessee under various agreements for real estate, equipment, plants and facilities, and information technology hardware that are currently accounted for as operating leases. Under the new standard, certain contracts, which were not previously reported as leases, will be now subject to lease accounting requirements. As a result, existing and newly qualifying operating leases under these new rules will increase reported assets and liabilities. The expected estimated right-of-use asset and

lease liability which will be recorded upon adoption is between $0.8 - $1.0 billion. Occidental is currently training employees, working with third-party consultants and finalizing testing on an internally developed software solution for the identification, documentation, tracking and accounting of leases as part of the adoption plan designed to address Occidental's population of leases under the revised definition of leases.

NOTE 4	REVENUE

On January 1, 2018, Occidental adopted ASC 606 using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under ASC 606, while prior period amounts have not been adjusted. There was no impact of adopting ASC 606 to the opening balance of retained earnings. There was no impact to the timing or amount of revenue recognized in the year ended December 31, 2018, as a result of the adoption of ASC 606.

Revenue recognition before the adoption of ASC 606

Prior to the adoption of ASC 606, revenue was recognized from oil and gas production when title was passed to the customer, which occurred when the product was shipped. Where oil was shipped by tanker, title passed when the tanker was loaded or product was received by the customer, depending on the shipping terms. This process occasionally caused a difference between actual production in a reporting period and sales volumes that had been recognized as revenue. Revenues from the production of oil and gas properties in which Occidental had an interest with other producers was recognized on the basis of Occidental’s net revenue interest.

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

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

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

Revenue recognition after the adoption of ASC 606

Revenue from customers is recognized when obligations under the terms of a contract with our customer 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 will not disclose revenue recognizable in future periods for unsatisfied performance obligations because the consideration related to those performance obligations is based on volume or market prices, which are variable.

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 it 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.

Chemical 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.

Midstream and Marketing 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 shows a reconciliation of revenue from customers to total net sales:

For the year ended December 31, (in millions)		2018
Revenue from customers		$	15,560
All other revenues (a)		2,264
Total net sales		$	17,824

(a) Includes net marketing revenue and chemical exchange contracts.

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. Excluding net marketing revenue, Midstream revenues are shown by the location of sale:

For the year ended December 31, 2018 (in millions)
Revenue by Product		United States				Middle East				Latin America				Other International				Eliminations				Total
Oil and Gas Segment
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 Segment		$	4,363			$	—			$	205			$	80			$	—			$	4,648
Midstream Segment
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

NOTE 5	INVENTORIES

Finished goods primarily represents crude oil, which is carried at the lower of weighted average cost or market value, and caustic soda and chlorine, which are valued under the LIFO method. Net carrying values of inventories valued under the LIFO method were $169 million and $172 million at December 31, 2018 and 2017, respectively. Inventories consisted of the following:

Balance at December 31, (in millions)		2018				2017
Raw materials		$	74			$	66
Materials and supplies		445				447
Finished goods		788				776
		1,307				1,289
Revaluation to LIFO		(47		)		(43		)
Total		$	1,260			$	1,246

NOTE 6	LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)		2018				2017
9.25% senior debentures due 2019		$	116			$	116
4.10% senior notes due 2021		1,249				1,249
3.125% senior notes due 2022		813				813
2.60% senior notes due 2022		400				400
2.70% senior notes due 2023		1,191				1,191
8.75% medium-term notes due 2023		22				22
3.50% senior notes due 2025		750				750
3.40% senior notes due 2026		1,150				1,150
3.00% senior notes due 2027		750				750
7.20% senior debentures due 2028		82				82
8.45% senior debentures due 2029		116				116
4.625% senior notes due 2045		750				750
4.40% senior notes due 2046		1,200				1,200
4.10% senior notes due 2047		750				750
4.20% senior notes due 2048		1,000				—
1.50% senior notes due 2018		—				500
Variable rate bonds due 2030 (1.9% and 1.8% as of December 31, 2018 and 2017, respectively )		68				68
		10,407				9,907
Less:
Unamortized discount, net		(36		)		(32		)
Debt issuance costs		(54		)		(47		)
Current maturities		(116		)		(500		)
Total		$	10,201			$	9,328

In January 2018, Occidental entered into a $3.0 billion revolving credit facility (2018 Credit Facility) which matures in January 2023, to replace the previously undrawn $2.0 billion revolving credit facility (2014 Credit Facility), which was scheduled to expire in August 2019. Borrowings under the 2018 Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Both credit facilities have similar terms and along with other debt agreements do not contain material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow or that would permit lenders to terminate their commitments or accelerate debt repayment. The 2018 Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur.

Occidental paid average annual facility fees of 0.08 percent in 2018 on the total commitment amounts of the 2018 Credit Facility. Occidental did not draw down any amounts under the 2018 Credit Facility during 2018. Occidental did not draw down any amounts under the 2014 Credit Facility during 2017 or 2016.

As of December 31, 2018, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock.

Occidental has provided guarantees on Dolphin Energy's debt, which are limited to certain political and other events. At December 31, 2018, and 2017, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on $244 million and $272 million, respectively, of Dolphin’s debt.

At December 31, 2018, principal payments on long-term debt aggregated approximately $10.4 billion, of which $116 million is due in 2019, zero is due in 2020, $1.2 billion is due in 2021, $1.2 billion is due in 2022, and $7.9 billion is due in 2023 and thereafter.

Occidental estimates the fair value of fixed-rate debt based on the quoted market prices for those instruments or on quoted market yields for similarly rated debt instruments, taking into account such instruments' maturities. The estimated fair values of Occidental’s debt at December 31, 2018, and 2017, substantially all of which were classified as Level 1, were approximately $10.3 billion and $10.4 billion, respectively, compared to carrying values of approximately $10.4 billion at December 31, 2018, and $9.9 billion at December 31, 2017. 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, 2018, and 2017, variable-rate debt constituted approximately one percent of Occidental's total debt.

NOTE 7	LEASE COMMITMENTS

Operating lease agreements include leases for real estate, equipment, plants and facilities, and information technology hardware. Occidental’s operating lease agreements frequently include renewal or purchase options and require the Company to pay for various fixed and variable cost including such things as utilities, taxes, insurance and maintenance expenses.

At December 31, 2018, future net minimum fixed lease payments for non-cancellable operating leases were the following (undiscounted):

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

Rental expense for operating leases was $175 million in 2018, $278 million in 2017 and $237 million in 2016.

NOTE 8	DERIVATIVES

Objective & Strategy

Occidental uses a variety of derivative financial instruments and physical contracts, including those designated as cash flow hedges, to manage its exposure to commodity price fluctuations, transportation commitments and to fix margins on the future sale of stored volumes of oil and natural gas. Where Occidental buys product for its own consumption or sells its production to a defined customer, Occidental may elect normal purchases and normal sales exclusions. Occidental usually 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 to lock in margins. Occidental also enters into derivative financial instruments for speculative or trading purposes; however, the results of any transactions are immaterial to the marketing portfolio. Refer to Note 1 for Occidental’s accounting policy on derivatives.

The financial instruments, not designated as hedges, will impact Occidental's earnings through mark-to-market until the offsetting future physical commodity is delivered. Physical inventory is carried at lower of cost or market on the balance sheet. A substantial majority of Occidental's physical derivative contracts are index-based and carry no mark-to-market value in earnings. Net gains and losses associated with derivative instruments not designated as hedging instruments are recognized currently in net sales. Net gains and losses attributable to derivatives instruments subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings.

Cash-Flow Hedges

Occidental’s marketing operations store natural gas purchased from third parties at Occidental’s leased storage facilities. Derivative instruments are used to fix margins on the future sales of the stored volumes. These agreements continue through 2019. As of December 31, 2018, and 2017, Occidental had approximately 5 Bcf and 7 Bcf of natural gas held in storage, respectively, and had cash-flow hedges for the forecasted sales, to be settled by physical delivery, of approximately 4 Bcf and 7 Bcf of stored natural gas, respectively. The amount of cash-flow hedges, including the ineffective portion, was immaterial for the years ended December 31, 2018, and 2017.

Derivatives Not Designated as Hedging Instruments

Forward unrealized instruments that are derivatives not designated as hedging instruments are required to be recorded on the income statement and balance sheet at fair value. The fair value represents an unrealized gain or loss between executed sales prices and market prices at the end of the period. The fair value does not reflect the realized or cash value of the instrument. Substantially all of the fair value of Occidental's derivative instruments not designated as hedges are used to manage its exposure to commodity price fluctuations and settle within three months at a weighted average contract price of $58.81 and $3.18 for crude oil and natural gas, respectively, at December 31, 2018. The remaining fair value of derivative instruments not designated as hedges was immaterial. The weighted average contract price was $57.38 and $2.73 for crude oil and natural gas, respectively, at December 31, 2017.

As of December 31, (in millions, except Long/(Short) volumes)		2018				2017
Unrealized gain (loss) on derivatives not designated as hedges
Oil commodity contracts		$	184			$	(47	)
Natural gas commodity contracts		$	5			$	1
Outstanding net volumes on derivatives not designated as hedges
Oil Commodity Contracts
Volume (MMBOE)		61				61
Natural gas commodity contracts
Volume (Bcf)		(142		)		(47		)

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 summarizes the fair value of the Company’s derivative assets and liabilities by input level within the fair-value hierarchy:

As of December 31, 2018				Fair Value Measurements Using									Netting (b)			Total Fair Value
(in millions)		Balance Sheet Location		Level 1			Level 2			Level 3
Assets:
Derivatives not designated as hedging instruments (a)
Commodity contracts		Other current assets		2,531			110			—			(2,392	)		249
	Long-term receivables and other assets, net		5			9			—			(6	)		8
Liabilities:
Cash-flow hedges (a)
Commodity contracts		Accrued liabilities		—			2			—			—			2
Derivatives not designated as hedging instruments (a)
Commodity contracts		Accrued liabilities		2,357			101			—			(2,392	)		66
	Deferred credits and liabilities		6			2			—			(6	)		2

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

(b)

These amounts do not include collateral. As of December 31, 2018, $45 million collateral received has been netted against derivative assets and collateral paid of $1 million has been netted against derivative liabilities. Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $178 million as of December 31, 2018, deposited by Occidental, has not been reflected in these derivative fair value tables. This collateral is included in other current assets in the consolidated balance sheets.

As of December 31, 2017				Fair Value Measurements Using									Netting (b)			Total Fair Value
(in millions)		Balance Sheet Location		Level 1			Level 2			Level 3
Assets:
Cash-flow hedges (a)
Commodity contracts		Other current assets		—			3			—			—			3
Derivatives not designated as hedging instruments (a)
Commodity contracts		Other current assets		485			227			—			(517	)		195
	Long-term receivables and other assets, net		1			2			—			(1	)		2
Liabilities:
Derivatives not designated as hedging instruments (a)
Commodity contracts		Accrued liabilities		535			222			—			(517	)		240
	Deferred credits and liabilities		1			3			—			(1	)		3

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

(b)

These amounts do not include collateral. As of December 31, 2017, no collateral received has been netted against derivative assets and collateral paid of $54 million has been netted against derivative liabilities. Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $70 million as of December 31, 2017, deposited by Occidental, has not been reflected in these derivative fair value tables. This collateral is included in other current assets in the consolidated balance sheets.

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 would need to post. Occidental believes that if it had received a one-notch reduction in its credit ratings, it would not have resulted in a material change in its collateral-posting requirements as of December 31, 2018, and 2017. The aggregate fair value of derivative instruments with credit-risk-related contingent features for which a net liability position existed was immaterial for both December 31, 2018, and December 31, 2017.

NOTE 9	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, 2018, Occidental participated in or monitored remedial activities or proceedings at 145 sites. The following table presents Occidental’s current and non-current environmental remediation reserves as of December 31, 2018, 2017 and 2016, the current portion of which is included in accrued liabilities ($120 million in 2018, $137 million in 2017, and $131 million in 2016) and the remainder in deferred credits and other liabilities - environmental remediation reserves ($762 million in 2018, $728 million in 2017, and $739 million in 2016). The reserves are grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA NPL sites and three categories of non-NPL sites - third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

($ amounts in millions)		2018							2017							2016
		Number of Sites			Reserve Balance				Number of Sites			Reserve Balance				Number of Sites			Reserve Balance
NPL sites		34			$	458			34			$	457			33			$	461
Third-party sites		68			168				70			157				68			163
Occidental-operated sites		14			115				15			108				17			106
Closed or non-operated Occidental sites		29			141				29			143				29			140
Total		145			$	882			148			$	865			147			$	870

As of December 31, 2018, Occidental’s environmental reserves exceeded $10 million each at 16 of the 145 sites described above, and 87 of the sites had reserves from $0 to $1 million each.

As of December 31, 2018, 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 reserves associated with NPL sites. The reserve balance above includes 17 NPL sites indemnified by Maxus.

Four of the 68 third-party sites — a Maxus-indemnified chrome site in New Jersey, a former copper mining and smelting operation in Tennessee, an active plant outside of the United States, and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities - accounted for 62 percent of Occidental’s reserves associated with these sites. The reserve balance above includes 9 third-party sites indemnified by Maxus.

Four sites - chemical plants in Kansas, Louisiana, New York and Texas - accounted for 64 percent of the reserves associated with the Occidental-operated sites.

Five other sites - a landfill in Western New York, former chemical plants in Tennessee, Washington and Delaware, and a closed coal mine in Pennsylvania - accounted for 61 percent of the reserves associated with closed or non-operated Occidental sites.

Environmental reserves vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation.

Based on current estimates, Occidental expects to expend funds corresponding to approximately 40 percent of the current environmental reserves at the sites described above over the next three to four years and the balance at these sites over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those liabilities recorded for environmental remediation at 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 reserve relating to its estimated allocable share of the costs to perform the design and the remediation called for in the AOC and the ROD, as well as for certain other Maxus-indemnified sites. Occidental's accrued estimated environmental reserve does not consider any recoveries for indemnified costs. Occidental’s ultimate share of this liability may be higher or lower than the reserved amount, and is subject to final design plans and the resolution of Occidental's allocable share with other potentially responsible parties. Occidental continues to evaluate the costs to be incurred to comply with the AOC, the ROD and to perform remediation at other Maxus-indemnified sites in light of the Maxus bankruptcy and the share of ultimate liability of other potentially responsible parties. 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:

(in millions)		2018				2017				2016
Operating Expenses
Oil and Gas		$	95			$	68			$	65
Chemical		80				78				75
Midstream and Marketing		15				15				11
		$	190			$	161			$	151
Capital Expenditures
Oil and Gas		$	75			$	77			$	43
Chemical		23				18				25
Midstream and Marketing		5				6				5
		$	103			$	101			$	73
Remediation Expenses
Corporate		$	47			$	39			$	61

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

NOTE 10	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 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 9, Occidental has disclosed its reserve balances for environmental remediation matters that satisfy this criteria. Reserve balances for matters, other than environmental remediation matters that satisfy this criteria as of December 31, 2018, and December 31, 2017, were not material to Occidental's consolidated balance sheet.

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. Occidental intends to vigorously defend against this claim in arbitration. A hearing on the merits has not been scheduled at this time.

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 sheet. 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 United States federal income tax purposes have been audited by the United States 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.

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, 2018, 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

OPC, its subsidiaries, or both, have entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling rigs and services, electrical power, steam and certain chemical raw materials. Occidental has certain other commitments under contracts, guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent liabilities. At December 31, 2018, total purchase obligations were $10.8 billion, which included approximately $1.9 billion, $1.4 billion, $1.3 billion, $1.1 billion, $1.0 billion and $4.1 billion that will be paid in 2019, 2020, 2021, 2022, 2023, and 2024 and thereafter, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2019 and thereafter, which were approximately $106 million.

NOTE 11	DOMESTIC AND FOREIGN INCOME TAXES

The domestic and foreign components of income (loss) from continuing operations before domestic and foreign income taxes were as follows:

For the years ended December 31, (in millions)		Domestic				Foreign				Total
2018		$	3,431			$	2,177			$	5,608
2017		$	(609	)		$	1,937			$	1,328
2016		$	(2,698	)		$	1,034			$	(1,664	)

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

For the years ended December 31, (in millions)		United States Federal				State and Local				Foreign				Total
2018
Current		$	(23	)		$	52			$	1,077			$	1,106
Deferred		422				12				(63		)		371
		$	399			$	64			$	1,014			$	1,477
2017
Current		$	(81	)		$	11			$	806			$	736
Deferred		(856		)		23				114				(719		)
		$	(937	)		$	34			$	920			$	17
2016
Current		$	(784	)		$	9			$	630			$	(145	)
Deferred		(504		)		(19		)		6				(517		)
		$	(1,288	)		$	(10	)		$	636			$	(662	)

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

For the years ended December 31,		2018			2017			2016
United States federal statutory tax rate		21	%		35	%		35	%
Other than temporary loss on available for sale investment in California Resources stock		—			—			(2	)
Enhanced oil recovery credit		(3	)		(9	)		5
Tax benefit due to write off of exploration blocks		—			—			14
Change in federal income tax rate		—			(44	)		—
Tax (benefit) expense due to reversal of indefinite reinvestment assertion		(2	)		7			—
Operations outside the United States		11			12			(14	)
State income taxes, net of federal benefit		1			2			—
Other		(2	)		(2	)		2
Worldwide effective tax rate		26	%		1	%		40	%

On December 22, 2017, Tax Reform was enacted, which made significant changes to the U.S. federal income tax law, including lowering the federal corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (AMT) and mandating a deemed repatriation of accumulated earnings and profits of U.S.-owned international corporations. Occidental disclosed, as part of its 2017 financial statements, provisional estimates of the income tax effects of Tax Reform.

The SEC provided a one-year measurement period for companies to complete the accounting requirements with regards to Tax Reform. As a result during 2018, Occidental recorded an additional tax benefit of $25 million that was primarily due to Occidental's review of proposed tax regulations and other regulatory guidance issued in 2018. Specifically, the regulations related to the allocation of expenses between the net operating losses generated in 2017 and the mandatory deemed repatriation of accumulated earnings from certain U.S.-owned international corporations that was included in 2017 taxable income. Upon review of the guidance issued during 2018, Occidental confirmed that the GILTI and BEAT provisions are not expected to have a material impact. Tax Reform also included new limitations on the ability of corporations to deduct interest expense. While these limitations did not adversely impact Occidental in 2018, under proposed regulations the limitations could significantly impact Occidental's ability to deduct interest expense in future years.

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2018, and 2017 were as follows:

		2018								2017
Tax effects of temporary differences (in millions)		Deferred Tax Assets				Deferred Tax Liabilities				Deferred Tax Assets				Deferred Tax Liabilities
Property, plant and equipment differences		$	—			$	2,089			$	—			$	2,272
Equity investments, partnerships and foreign subsidiaries		—				161				—				134
Environmental reserves		195				—				191				—
Postretirement benefit accruals		176				—				145				—
Deferred compensation and benefits		170				—				151				—
Asset retirement obligations		280				—				228				—
Foreign tax credit carryforwards		2,356				—				2,750				—
General business credit carryforwards		429				—				407				—
Net operating loss carryforward		29				—				437				—
Federal benefit of state income taxes		18				—				10				—
All other		93				—				146				—
Subtotal		3,746				2,250				4,465				2,406
Valuation allowance		(2,403		)		—				(2,640		)		—
Total deferred taxes		$	1,343			$	2,250			$	1,825			$	2,406

Total deferred tax assets, after valuation allowances, were $1.3 billion and $1.8 billion as of December 31, 2018, and 2017, respectively. Occidental expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The increase in net deferred tax liability in 2018 over 2017 is primarily due to the utilization of net operating loss carryforwards in 2018.

As of December 31, 2018, Occidental had foreign tax credit carryforwards of $2.4 billion, state operating loss carryforwards of $28 million and state tax credit carryforwards of $41 million. These carryforward balances have varying carryforward periods through 2038. Occidental has recorded a valuation allowance for all of the foreign tax credit carryforwards, $14 million of the tax-effected state net operating loss carryforwards and $33 million of the state tax credit carryforwards.

At December 31, 2018, Occidental made an indefinite reinvestment assertion with regard to a portion of its foreign undistributed earnings and, as a result, a deferred tax liability of $99 million was released.

A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated international subsidiaries aggregating approximately $837 million at December 31, 2018, 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 $199 million would be required.

Discontinued operations include income tax charges of $249 million in 2016.

As of December 31, 2018, Occidental had no liabilities for unrecognized tax benefits included in deferred credits and other liabilities – other. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

For the years ended December 31, (in millions)		2018				2017				2016
Balance at January 1,		$	22			$	22			$	22
Reductions based on tax positions related to prior years and settlements		(22		)		—				—
Balance at December 31,		$	—			$	22			$	22

Management believes it is unlikely that Occidental’s liabilities for unrecognized tax benefits related to existing matters would increase or decrease within the next 12 months by a material amount. Occidental cannot reasonably estimate a range of potential changes in such benefits due to the unresolved nature of the various audits.

Occidental has recognized $68 million and $76 million in federal income tax receivables at December 31, 2018, and 2017, respectively, which was recorded in other current assets. In addition, Occidental has recognized $68 million and $221 million in federal alternative minimum tax non-current receivables at December 31, 2018, and 2017, 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 10 for a discussion of these matters.

Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes and these amounts were not material for the years ended December 31, 2018, 2017 and 2016.

NOTE 12	STOCKHOLDERS' EQUITY

The following is a summary of common stock issuances:

Shares in thousands		Common Stock
Balance, December 31, 2015		891,360
Issued		843
Options exercised and other, net		12
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

TREASURY STOCK

The total number of shares authorized for Occidental's share repurchase program is 185 million shares of which 46.9 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 2018, 16.9 million shares were purchased at an average price of $74.92 under the program. No shares were purchased under the program in 2017 and 2016. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year. As of December 31, 2018, 2017 and 2016, treasury stock shares numbered 145.7 million, 128.4 million and 128.0 million, respectively.

NONREDEEMABLE PREFERRED STOCK

Occidental has authorized 50,000,000 shares of preferred stock with a par value of $1.00 per share. At December 31, 2018, 2017 and 2016, Occidental had no outstanding shares of preferred stock.

EARNINGS PER SHARE

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

(in millions, except per-share amounts)		2018				2017				2016
Income (loss) from continuing operations attributable to common stock		$	4,131			$	1,311			$	(1,002	)
Income from discontinued operations		—				—				428
Net income (loss)		4,131				1,311				(574		)
Less: Net income allocated to participating securities		(17		)		(6		)		—
Net income (loss), net of participating securities		$	4,114			$	1,305			$	(574	)
Weighted average number of basic shares		761.7				765.1				763.8
Basic earnings (loss) per common share		$	5.40			$	1.71			$	(0.75	)
Net income (loss), net of participating securities		$	4,114			$	1,305			$	(574	)
Weighted average number of basic shares		761.7				765.1				763.8
Dilutive securities		1.6				0.8				—
Total diluted weighted average common shares		763.3				765.9				763.8
Diluted earnings (loss) per common share		$	5.39			$	1.70			$	(0.75	)

ACCUMULATED OTHER COMPREHENSIVE LOSS

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

Balance at December 31, (in millions)		2018				2017
Foreign currency translation adjustments		$	(7	)		$	(7	)
Unrealized gains on derivatives		5				—
Pension and postretirement adjustments (a)		(170		)		(251		)
Total		$	(172	)		$	(258	)

(a)	See Note 14 for further information.

NOTE 13	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). Awards issued under the superseded 2005 LTIP, and subsequently forfeited after adoption of the 2015 LTIP, increase the shares available for issuance under the 2015 LTIP. An aggregate of 80 million shares of Occidental common stock were authorized for issuance and approximately 6.8 million shares had been allocated to employee awards through December 31, 2018. As of December 31, 2018, approximately 70.3 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 70.3 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, ROCEIs, ROAIs and TSRIs.

During 2018, non-employee directors were granted awards for 31,835 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.

Total share-based compensation expense recognized in income related to continuing and discontinued operations and the associated tax benefit for the years ended December 31, 2018, 2017, and 2016 was $180 million, $150 million, and $121 million, respectively. The income tax benefit associated with this expense was $47 million, $32 million, and $43 million in the years ended December 31, 2018, 2017, and 2016, respectively.

As of December 31, 2018, unrecognized compensation expense for all unvested stock-based incentive awards was $193.4 million. This expense is expected to be recognized over a weighted-average period of 1.6 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 are settled in cash or stock at the time of vesting. 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. For those awards that cliff vest between one to three years, dividend

equivalents are accumulated during the vesting or performance period, as appropriate, and are paid upon vesting or performance certification, as appropriate.

The weighted-average, grant-date fair values of cash-settled RSUs granted in 2018, 2017 and 2016 were $75.86, $66.62, and $75.57 per share, respectively. The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2018, 2017, and 2016 were $69.87, $67.21, and $74.82, respectively. Cash-Settled RSUs resulted in payments of $18 million, $23 million, and $41 million, during the years ended December 31, 2018, 2017 and 2016, respectively. The fair value of RSUs settled in shares during the years ended December 31, 2018, 2017 and 2016 was $109 million, $64 million, and $31 million, respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2018, is presented below:

		Cash-Settled									Stock-Settled
		RSUs (000's)			Weighted-Average Grant-Date Fair Value						RSUs (000's)			Weighted-Average Grant-Date Fair Value
Unvested at January 1		269				$	71.58				3,951				$	73.24
Granted		133				75.86					1,689				69.87
Vested		(212	)			72.23					(1,469	)			69.89
Forfeitures		(4	)			70.06					(200	)			70.37
Unvested at December 31		186				73.93					3,971				73.19

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 percent 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, 2018, 2017 and 2016 was $12 million, $5 million, and $8 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
Year Granted		2018				2017				2016
Assumptions used:
Risk-free interest rate		2.3		%		1.5		%		0.8		%
Dividend yield		4.4		%		4.5		%		3.9		%
Volatility factor		24		%		25		%		24		%
Expected life (years)		3				3				3
Grant-date fair value of underlying Occidental common stock		$	69.87			$	67.21			$	76.83

A summary of Occidental’s unvested TSRIs as of December 31, 2018, and changes during the year ended December 31, 2018, is presented below:

		TSRIs
		Awards (000’s)			Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1		1,152				$	71.58
Granted		448				69.87
Vested (a)		(145	)			72.54
Forfeitures		(11	)			69.87
Unvested at December 31		1,444				70.97

(a)	The payout at vesting was 100% of the target.

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 in 2018. The intrinsic value of options exercised during the years ended December 31, 2018, 2017, and 2016 was insignificant.

The fair value of each option is initially measured on the grant date using the Black Scholes option valuation model. The expected life is estimated based on the vesting and expiration terms of the award. The volatility factors are based on the historical volatilities of Occidental common stock over the expected lives as estimated on the grant date. The risk-free interest rate is the implied yield available on U.S. Treasury Strips at the grant date with a remaining term equal to the expected life of the measured instrument. The dividend yield is the expected annual dividend yield over the expected life, expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by employees who receive stock-based incentive awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.

The following is a summary of option transactions during the year ended December 31, 2018:

		SARs & Options (000's)			Weighted-Average Exercise Price				Weighted-Average Remaining Contractual Term (yrs)		Aggregate Intrinsic Value (000’s)
Beginning balance, January 1		549			$	79.98
Exercised		(19	)		79.98
Ending balance, December 31		530			79.98				3.1		$	—
Exercisable at December 31		530			79.98				3.1		$	—

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 return on assets, return on capital employed, or cash return on capital employed 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 percent of the target award. Dividend equivalents are accumulated and paid upon certification of the award.

		CROCEI, ROCEI, and ROAI
		Awards (000's)			Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1		268				$	84.46
Granted		80				69.87
Vested (a)		(132	)			101.95
Forfeited		(6	)			69.87
Unvested at December 31		210				71.60

(a)	Presented at the target payouts. The payout at vesting was 97.5% of the target for approximately 6,000 shares. The payout at vesting was 0% of target for the remaining 126,000 shares.

NOTE 14	RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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

DEFINED CONTRIBUTION PLANS

All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, 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 $201 million and $175 million as of December 31, 2018, and 2017, respectively, and Occidental expensed $152 million in 2018, $130 million in 2017 and $113 million in 2016 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited. Approximately 400 domestic and 1,000 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 $182 million in 2018, $181 million in 2017 and $182 million in 2016.

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 PPO 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.

OBLIGATIONS AND FUNDED STATUS

The following tables show the amounts recognized in the consolidated balance sheets of Occidental related to its pension and postretirement benefit plans:

(in millions)		Pension Benefits								Postretirement Benefits
As of December 31,		2018				2017				2018				2017
Amounts recognized in the consolidated balance sheet:
Other assets		$	60			$	82			$	—			$	—
Accrued liabilities		(25		)		(5		)		(45		)		(59		)
Deferred credits and other liabilities — pension and postretirement obligations		(46		)		(65		)		(763		)		(940		)
		$	(11	)		$	12			$	(808	)		$	(999	)

Accumulated other comprehensive loss included the following after-tax balances:
Net loss		$	91			$	59			$	151			$	192
Prior service cost		—				—				(72		)		1
		$	91			$	59			$	79			$	193

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

		Pension Benefits								Postretirement Benefits
For the years ended December 31,		2018				2017				2018				2017
Changes in the benefit obligation:
Benefit obligation — beginning of year		$	391			$	399			$	999			$	950
Service cost — benefits earned during the period		5				6				23				21
Interest cost on projected benefit obligation		15				17				34				38
Actuarial (gain) loss		(19		)		14				(90		)		61
Foreign currency exchange rate gain		(3		)		—				—				—
Liability gain due to curtailment		—				(2		)		—				(9		)
Special termination benefits		—				1				—				—
Benefits paid		(40		)		(44		)		(57		)		(62		)
Settlements		—				—				—				—
Plan amendments		—				—				(101		)		—
Benefit obligation — end of year		$	349			$	391			$	808			$	999
Changes in plan assets:
Fair value of plan assets — beginning of year		$	403			$	386			$	—			$	—
Actual return on plan assets		(33		)		52				—				—
Foreign currency exchange rate loss		—				—				—				—
Employer contributions		8				9				—				—
Benefits paid		(40		)		(44		)		—				—
Settlements		—				—				—				—
Fair value of plan assets — end of year		$	338			$	403			$	—			$	—
Funded/(Unfunded) status:		$	(11	)		$	12			$	(808	)		$	(999	)

The following table sets forth details of the obligations and assets of Occidental's defined benefit pension plans:

(in millions)		Accumulated Benefit Obligation in Excess of Plan Assets								Plan Assets in Excess of Accumulated Benefit Obligation
As of December 31,		2018				2017				2018				2017
Projected Benefit Obligation		$	173			$	161			$	176			$	230
Accumulated Benefit Obligation		$	169			$	157			$	176			$	230
Fair Value of Plan Assets		$	98			$	91			$	240			$	312

Occidental does not expect any plan assets to be returned during 2019.

COMPONENTS OF NET PERIODIC BENEFIT COST

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

		Pension Benefits												Postretirement Benefits
For the years ended December 31, (in millions)		2018				2017				2016				2018				2017				2016
Net periodic benefit costs:
Service cost — benefits earned during the period		$	5			$	6			$	7			$	23			$	21			$	20
Interest cost on projected benefit obligation		15				17				18				34				38				39
Expected return on plan assets		(25		)		(24		)		(24		)		—				—				—
Recognized actuarial loss		7				10				12				14				14				15
Other costs and adjustments		1				3				4				(2		)		1				—
Net periodic benefit cost		$	3			$	12			$	17			$	69			$	74			$	74

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 $9 million and zero, respectively.

The estimated net loss and prior service cost for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $9 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:

		Pension Benefits						Postretirement Benefits
For the years ended December 31,		2018			2017			2018			2017
Benefit Obligation Assumptions:
Discount rate		4.09	%		3.45	%		4.29	%		3.61	%
Net Periodic Benefit Cost Assumptions:
Discount rate for January 1 - August 31 expense		3.45	%		3.90	%		3.61	%		4.15	%
Discount rate for September 1 - December 31 expense		3.45	%		3.90	%		4.14	%		4.15	%
Assumed long-term rate of return on assets		6.50	%		6.50	%		—			—

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2018 and 2017. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end.

In 2018, Occidental adopted the Society of Actuaries 2018 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 improvement scale reflects additional data that the Social Security Administration has released since the MP-2017 scale released in 2017. This additional data shows a lower degree of mortality improvement than previously reflected. The changes in the mortality improvement scale results in a decrease of $1 million and $1 million in the pension and postretirement benefit obligation at December 31, 2018, respectively.

For pension plans outside the United States, Occidental based its discount rate on rates indicative of government or investment grade corporate debt in the applicable country, taking into account hyperinflationary environments when necessary. The discount rates used for the foreign pension plans ranged from 1.0 percent to 8.9 percent at December 31, 2018 and from 1.0 percent to 10.8 percent at December 31, 2017. The average rate of increase in future compensation levels ranged from 1.0 percent to 8.0 percent in 2018, 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 22-34 percent in 2019, 6-10 percent in 2020, then grading down to 4.50 percent in 2027 and beyond. Health care cost trend rates used for non-MAPD plans are 7.75 percent in 2018, then grading down to 4.50 percent in 2025 and beyond. In 2017, health care cost trend rates were projected at an assumed U.S. Consumer Price Index (CPI) increase of 1.97 percent for salaried employees. For union employees, Occidental projected that health care cost trend rates would decrease from 8.0 percent in 2017 until they reached 4.50 percent in 2025, and remain at 4.50 percent thereafter.

A 1 percent increase or a 1 percent decrease in these assumed health care cost trend rates would result in an increase of $102 million or a reduction of $82 million, respectively, in the postretirement benefit obligation and increase of $10 million or a reduction of $8 million in the annual service and interest costs as of December 31, 2018.

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

FAIR VALUE OF PENSION PLAN ASSETS

Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk. The investments are monitored by Occidental’s Pension and Retirement Trust and Investment Committee (Investment Committee) in its role as fiduciary. The Investment Committee, consisting of senior Occidental executives, selects and employs various external professional investment management firms to manage specific investments across the spectrum of asset classes. Equity investments are diversified across U.S. and non-U.S. stocks, as well as differing styles and market capitalizations. Other asset classes, such as private equity and real estate, may be used with the goals of enhancing long-term returns and improving portfolio diversification. The target allocation of plan assets is 65 percent equity securities and 35 percent debt securities. Investment performance is measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.

The fair values of Occidental’s pension plan assets by asset category are as follows:

(in millions)		Fair Value Measurements at December 31, 2018, Using
Description		Level 1				Level 2				Level 3				Total
Asset Class:
U.S. government securities		$	17			$	—			$	—			$	17
Corporate bonds (a)		—				66				—				66
Common/collective trusts (b)		—				9				—				9
Mutual funds:
Bond funds		31				—				—				31
Blend funds		48				—				—				48
Common and preferred stocks (c)		141				—				—				141
Other		—				31				—				31
Total pension plan assets (d)		$	237			$	106			$	—			$	343

(in millions)		Fair Value Measurements at December 31, 2017, Using
Description		Level 1				Level 2				Level 3				Total
Asset Class:
U.S. government securities		$	12			$	—			$	—			$	12
Corporate bonds (a)		—				83				—				83
Common/collective trusts (b)		—				20				—				20
Mutual funds:
Bond funds		19				—				—				19
Blend funds		59				—				—				59
Common and preferred stocks (c)		188				—				—				188
Other		—				30				—				30
Total pension plan assets (d)		$	278			$	133			$	—			$	411

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

(b)	This category includes investment funds that primarily invest in U.S. and non-U.S. common stocks and fixed-income securities.

(c)	This category represents direct investments in common and preferred stocks from diverse U.S. and non-U.S. industries.

(d)	Amounts exclude net payables of approximately $6 million and $8 million as of December 31, 2018 and 2017, respectively.

Occidental expects to contribute $26 million in cash to its defined benefit pension plans during 2019. Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows:

For the years ended December 31, (in millions)		Pension Benefits				Postretirement Benefits
2019		$	60			$	46
2020		$	27			$	50
2021		$	28			$	50
2022		$	27			$	50
2023		$	26			$	50
2024 - 2028		$	129			$	249

NOTE 15	INVESTMENTS AND RELATED-PARTY TRANSACTIONS

EQUITY INVESTMENTS

As of December 31, 2018, and 2017, investments in unconsolidated entities comprised $1.7 billion and $1.5 billion of equity-method investments, respectively.

As of December 31, 2018, Occidental’s equity investments consisted mainly of an 11 percent interest in the general partner which owns approximately 40 percent of Plains All American Pipeline, LP , a 24.5-percent interest in the stock of Dolphin Energy, a 50-percent interest in OxyChem Ingleside facility, and various other partnerships and joint ventures. Equity investments paid dividends of $329 million, $297 million, and $224 million to Occidental in 2018, 2017 and 2016, respectively. As of December 31, 2018, cumulative undistributed earnings of equity-method investees since they were acquired was immaterial. As of December 31, 2018, Occidental's investments in equity investees exceeded the underlying equity in net assets by approximately $636 million, of which $464 million represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

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

For the years ended December 31, (in millions)		2018				2017				2016
Revenues and other income		$	1,932			$	1,252			$	1,238
Costs and expenses		1,527				973				1,043
Net income		$	405			$	279			$	195
As of December 31, (in millions)		2018				2017
Current assets		$	547			$	602
Non-current assets		$	2,139			$	2,072
Current liabilities		$	237			$	247
Long-term debt		$	1,042			$	1,174
Other non-current liabilities		$	22			$	66
Stockholders’ equity		$	1,385			$	1,187

Occidental’s investment in Dolphin, which was acquired in 2002, consists of two separate economic interests through which Occidental owns (i) a 24.5-percent undivided interest in the upstream operations under an agreement which is proportionately consolidated in the financial statements; and (ii) a 24.5-percent interest in the stock of Dolphin Energy, which operates a pipeline and is accounted for as an equity investment.

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 2018, 2017 and 2016, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

For the years ended December 31, (in millions)		2018				2017				2016
Sales (a)		$	805			$	636			$	602
Purchases (b)		$	502			$	387			$	7
Services		$	52			$	38			$	17
Advances and amounts due from		$	63			$	63			$	59
Amounts due to		$	46			$	45			$	—

(a)

In 2018, 2017 and 2016, sales of Occidental-produced oil and NGL to Plains Pipeline affiliates accounted for 89 percent, 86 percent and 89 percent of these totals, respectively. Sales to Plains Pipeline affiliates related to Occidental's oil and gas production are disclosed above. In addition to these sales, Occidental conducts marketing activities with Plains Pipeline affiliates for oil, NGL and transportation. Net margins associated with these marketing activities are negligible.

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

NOTE 16	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 crude oil prices. Occidental determined that the portion of this contract linked to NYMEX oil prices is not clearly and closely related to the host contract, and Occidental therefore bifurcated this embedded pricing feature from its host contract and accounts for it at fair value in the consolidated financial statements.

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

(in millions)		Fair Value Measurements at December 31, 2018, Using														Netting and Collateral				Total Fair Value
Description				Level 1				Level 2				Level 3
Liabilities:
Embedded derivative		Accrued liabilities		$	—			$	66			$	—			$	—			$	66
	Deferred credits and liabilities		$	—			$	116			$	—			$	—			$	116

(in millions)		Fair Value Measurements at December 31, 2017, Using														Netting and Collateral				Total Fair Value
Description				Level 1				Level 2				Level 3
Liabilities:
Embedded derivative		Accrued liabilities		$	—			$	39			$	—			$	—			$	39
	Deferred credits and liabilities		$	—			$	147			$	—			$	—			$	147

FAIR VALUES – NONRECURRING

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. As the end of the contract period for Qatar approaches, significant changes to estimated future cash flows could result in additional impairment charges.

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.

During 2016, Occidental recognized pre-tax impairment charges of $15 million related to proved oil and gas properties.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash and cash equivalents and other on-balance sheet financial instruments, other than fixed-rate debt, approximate fair value. See Note 6 for the fair value of Long-term Debt.

NOTE 17	INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Results of industry segments and geographic areas exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from dispositions of segment and geographic area assets and income from the segments' equity investments. Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.

Identifiable assets are those assets used in the operations of the segments. Corporate assets consist of cash and restricted cash, certain corporate receivables and PP&E.

Industry Segments
(in millions)		Oil and Gas				Chemical				Midstream and Marketing				Corporate and Eliminations				Total
Year ended December 31, 2018
Net sales		$	10,441		(a)	$	4,657		(b)	$	3,656		(c)	$	(930	)		$	17,824
Pretax operating profit (loss)		$	2,442		(d)	$	1,159			$	2,802		(e)	$	(795	)	(f)	$	5,608
Income taxes		—				—				—				(1,477		)	(g)	(1,477		)
Net income (loss) attributable to common stock		$	2,442			$	1,159			$	2,802			$	(2,272	)		$	4,131
Investments in unconsolidated entities		$	—			$	733			$	947			$	—			$	1,680
Property, plant and equipment additions, net (h)		$	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		(a)	$	4,355		(b)	$	1,157		(c)	$	(874	)		$	12,508
Pretax operating profit (loss)		$	1,111		(d)	$	822			$	85		(e)	$	(690	)	(f)	$	1,328
Income taxes		—				—				—				(17		)	(g)	(17		)
Net income (loss) attributable to common stock		$	1,111			$	822			$	85			$	(707	)		$	1,311
Investments in unconsolidated entities		$	—			$	771			$	739			$	5			$	1,515
Property, plant and equipment additions, net (h)		$	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
Year ended December 31, 2016
Net sales		$	6,377		(a)	$	3,756		(b)	$	684		(c)	$	(727	)		$	10,090
Pretax operating profit (loss)		$	(636	)	(d)	$	571		(i)	$	(381	)	(e)	$	(1,218	)	(f)	$	(1,664	)
Income taxes		—				—				—				662			(g)	662
Discontinued operations, net		—				—				—				428			(j)	428
Net income (loss) attributable to common stock		$	(636	)		$	571			$	(381	)		$	(128	)		$	(574	)
Investments in unconsolidated entities		$	—			$	730			$	666			$	5			$	1,401
Property, plant and equipment additions, net (h)		$	1,998			$	353			$	370			$	59			$	2,780
Depreciation, depletion and amortization		$	3,575			$	340			$	313			$	40			$	4,268
Total assets		$	24,130			$	4,348			$	11,059			$	3,572			$	43,109
(See footnotes on next page)

Footnotes:

(a)	Oil sales represented approximately 90 percent of the oil and gas segment net sales for the years ended December 31, 2018, 2017 and 2016.

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

		Basic Chemicals		Vinyls		Other Chemicals
Year ended December 31, 2018		59%		41%		—
Year ended December 31, 2017		57%		42%		1%
Year ended December 31, 2016		57%		40%		3%

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

		Marketing		Gas Plants		Power		Other Midstream and Marketing
Year ended December 31, 2018		62%		27%		10%		1%
Year ended December 31, 2017		(11)%		69%		29%		13%
Year ended December 31, 2016		(52)%		92%		44%		16%

(d)

The 2018 amount includes $416 million for the impairment of proved oil properties and inventory in Qatar ISND and ISSD due to the decline in crude oil prices.The 2017 amount includes 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. The 2016 amount includes pre-tax asset sale gains of $121 million and $59 million related to Piceance and South Texas oil and gas properties, pre-tax charges of $61 million related to the sale of Libya and the exit from Iraq, and pre-tax gain of $24 million for other related items.

(e)	The 2018 amount includes pre-tax asset sale gains of $907 million on the sale of non-core domestic midstream assets. The 2017 amount includes pre-tax charges of $120 million related to asset impairments of idled facilities. The 2016 amount includes pre-tax charges of $160 million related to the termination of crude oil supply contracts.

(f)

There were no significant corporate transactions and events affecting 2018 and 2017 results. Significant corporate transactions and events affecting 2016 earnings, included charges of $541 million related to a reserve for doubtful accounts, $78 million loss on the distribution of the remaining CRC stock and gains related to the Ecuador settlement. The tax effect of these pre-tax adjustments, as well as those in footnotes (d), (e), (i), and (j) was $198 million, $392 million, and $424 million for the years ended December 31, 2018, 2017, and 2016, respectively.

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

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

(i)	The 2016 amount includes gain on sale of $57 million and $31 million related to Occidental Tower in Dallas, Texas, and a non-core specialty chemicals business, respectively.

(j)	Includes discontinued operations from Ecuador.

GEOGRAPHIC AREAS

(in millions)		Net sales (a)												Property, plant and equipment, net
For the years ended December 31,		2018				2017				2016				2018				2017				2016
United States		$	13,351			$	8,959			$	7,017			$	23,594			$	22,863			$	24,004
International
Qatar		1,701				1,394				1,206				741				1,236				1,299
Oman		1,667				1,397				1,101				2,048				1,962				1,858
United Arab Emirates		1,021				808				664				4,051				4,241				4,373
Colombia		715				555				463				927				807				741
Other International		299				269				366				76				65				62
Total International		5,403				4,423				3,800				7,843				8,311				8,333
Eliminations		(930		)		(874		)		(727		)		—				—				—
Total		$	17,824			$	12,508			$	10,090			$	31,437			$	31,174			$	32,337

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

2018 Quarterly Financial Data (Unaudited)	Occidental Petroleum Corporation and Subsidiaries
in millions, except per-share amounts

Three months ended		March 31				June 30				September 30				December 31
Segment net sales
Oil and gas		$	2,454			$	2,531			$	2,889			$	2,567
Chemical		1,154				1,176				1,185				1,142
Midstream and marketing		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		(a)	$	145		(a)
Chemical		298				317				321				223
Midstream and marketing		179				250				1,698			(b)	675			(b)
		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 stock		$	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)	Included pre-tax impairments on Qatar ISND and ISSD proved oil properties and inventory of $196 million and $220 million in the third and fourth quarter, respectively.

(b)	Included pre-tax asset sale gains on the divestiture of non-core domestic midstream assets of $902 million and $5 million in the third and fourth quarter, respectively.

2017 Quarterly Financial Data (Unaudited)	Occidental Petroleum Corporation and Subsidiaries
in millions, except per-share amounts

Three months ended		March 31				June 30				September 30				December 31
Segment net sales
Oil and gas		$	1,894			$	1,848			$	1,865			$	2,263
Chemical		1,068				1,156				1,071				1,060
Midstream and marketing		211				270				266				410
Eliminations		(216		)		(214		)		(203		)		(241		)
Net sales		$	2,957			$	3,060			$	2,999			$	3,492
Gross profit		$	521			$	508			$	571			$	1,001
Segment earnings
Oil and gas		$	220			$	627		(a)	$	220		(a)	$	44		(a)
Chemical		170				230				200				222
Midstream and marketing		(47		)		119			(b)	4				9			(b)
		343				976				424				275
Unallocated corporate items
Interest expense, net		(78		)		(81		)		(85		)		(80		)
Income taxes		(78		)		(285		)		(85		)		431
Other		(70		)		(103		)		(64		)		(129		)
Net income (loss)		$	117			$	507			$	190			$	497
Basic earnings per common share		$	0.15			$	0.66			$	0.25			$	0.65
Diluted earnings per common share		$	0.15			$	0.66			$	0.25			$	0.65
Dividends per common share		$	0.76			$	0.76			$	0.77			$	0.77

(a)

Included pre-tax asset sale gains of $0.5 billion in the second quarter related to the sale of South Texas operations, $81 million in the third quarter related to the sale of non-core acreage in the Permian Basin, and approximately $55 million in the fourth quarter related to the sale of non-core proved and unproved acreage in the Permian Basin. The fourth quarter also included impairments of $397 million on non-core proved and unproved Permian acreage.

(b)	Included second quarter pre-tax non-cash fair value gain of $94 million on Plains Pipeline equity investment and fourth quarter pre-tax charges of $120 million related to idled midstream facilities.

Supplemental Oil and Gas Information (Unaudited)

The following tables set forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of oil (including condensate), 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. For the 2018, 2017 and 2016 disclosures, the calculated average West Texas Intermediate oil prices were $65.56, $51.34 and $42.75 per barrel, respectively. The calculated average Brent oil prices for 2018, 2017 and 2016 disclosures were $72.20, $54.93 and $44.49, per barrel, respectively. The calculated average Henry Hub natural gas prices for 2018, 2017 and 2016 were $3.10, $3.08 and $2.55 per MMBtu, respectively. Reserves are stated net of applicable royalties. Estimated reserves include Occidental's economic interests under production-sharing contracts (PSCs) and other similar economic arrangements. In addition, discussions of oil and gas production or volumes, in general, refer to sales volumes unless the context requires or it is indicated otherwise.

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

(Unaudited)

Oil Reserves
in millions of barrels (MMbbl)
		United			Latin			Middle
		States			America			East (a)			Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2015		915			77			317			1,309
Revisions of previous estimates (b)		(90	)		4			86			—
Improved recovery		114			2			9			125
Extensions and discoveries		—			—			2			2
Purchases of proved reserves		90			—			—			90
Sales of proved reserves (c)		—			—			(26	)		(26	)
Production		(69	)		(12	)		(62	)		(143	)
Balance at December 31, 2016		960			71			326			1,357
Revisions of previous estimates (b)		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 (c)		(13	)		—			—			(13	)
Production		(73	)		(11	)		(55	)		(139	)
Balance at December 31, 2017		1,107			82			326			1,515
Revisions of previous estimates (b)		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 (c)		(12	)		—			—			(12	)
Production		(91	)		(11	)		(51	)		(153	)
Balance at December 31, 2018		1,186			96			301			1,583
PROVED DEVELOPED RESERVES
December 31, 2015		673			77			278			1,028
December 31, 2016		670			69			298			1,037
December 31, 2017		772			77			279			1,128
December 31, 2018 (d)		843			77			240			1,160
PROVED UNDEVELOPED RESERVES (e)
December 31, 2015		242			—			39			281
December 31, 2016		290			2			28			320
December 31, 2017		335			5			47			387
December 31, 2018		343			19			61			423

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

(b)	Revisions of previous estimates in 2018 primarily reflected positive price revisions in Permian Basin. Revisions of previous estimates in 2017 primarily reflected positive revisions in Permian Basin and Oman. Revisions of previous estimates in 2016 were primarily price and price-related.

(c)	Sales of proved reserves in 2018 were related to sales of non-core acreage in the Permian Basin. Sales of proved reserves in 2017 were primarily related to sales of South Texas and non-core acreage in the Permian Basin. Sales of proved reserves in 2016 were related to the sale of Libya.

(d)	Approximately 12 percent of the proved developed reserves at December 31, 2018, are nonproducing, primarily associated with Oman and Permian EOR.

(e)

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.

(Unaudited)

NGL Reserves
in millions of barrels (MMbbl)
		United			Latin			Middle
		States			America			East			Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2015		186			—			144			330
Revisions of previous estimates (a)		1			—			70			71
Improved recovery		28			—			—			28
Extensions and discoveries		—			—			—			—
Purchases of proved reserves		26			—			—			26
Sales of proved reserves		(3	)		—			(2	)		(5	)
Production		(19	)		—			(11	)		(30	)
Balance at December 31, 2016		219			—			201			420
Revisions of previous estimates (a)		11			—			(2	)		9
Improved recovery		23			—			10			33
Extensions and discoveries		—			—			—			—
Purchases of proved reserves		21			—			—			21
Sales of proved reserves (b)		(7	)		—			—			(7	)
Production		(20	)		—			(11	)		(31	)
Balance at December 31, 2017		247			—			198			445
Revisions of previous estimates (a)		7			—			15			22
Improved recovery		47			—			—			47
Extensions and discoveries		—			—			—			—
Purchases of proved reserves		11			—			—			11
Sales of proved reserves (b)		(3	)		—			—			(3	)
Production		(25	)		—			(11	)		(36	)
Balance at December 31, 2018		284			—			202			486
PROVED DEVELOPED RESERVES
December 31, 2015		141			—			112			253
December 31, 2016		149			—			164			313
December 31, 2017		161			—			153			314
December 31, 2018 (c)		196			—			145			341
PROVED UNDEVELOPED RESERVES (d)
December 31, 2015		45			—			32			77
December 31, 2016		70			—			37			107
December 31, 2017		86			—			45			131
December 31, 2018		88			—			57			145

(a)	Revisions of previous estimates were primarily due to prices.

(b)	Sales of proved reserves in 2018 were related to sales of non-core acreage in the Permian Basin. Sales of proved reserves in 2017 were primarily related to the sale of South Texas.

(c)	Approximately 6 percent of the proved developed reserves at December 31, 2018, are nonproducing, primarily associated with Permian EOR.

(d)

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.

(Unaudited)

Natural Gas Reserves
in billions of cubic feet (Bcf)
		United			Latin			Middle
		States			America			East (a)			Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2015		1,019			19			2,330			3,368
Revisions of previous estimates (b)		(19	)		(10	)		554			525
Improved recovery		138			—			51			189
Extensions and discoveries		—			—			2			2
Purchases of proved reserves		128			—			—			128
Sales of proved reserves (c)		(89	)		—			—			(89	)
Production		(132	)		(3	)		(214	)		(349	)
Balance at December 31, 2016		1,045			6			2,723			3,774
Revisions of previous estimates (b)		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 (c)		(146	)		—			—			(146	)
Production		(108	)		(3	)		(185	)		(296	)
Balance at December 31, 2017		1,205			12			2,614			3,831
Revisions of previous estimates (b)		(25	)		—			191			166
Improved recovery		329			1			17			347
Extensions and discoveries		—			—			4			4
Purchases of proved reserves		69			—			—			69
Sales of proved reserves (c)		(14	)		—			—			(14	)
Production		(119	)		(2	)		(187	)		(308	)
Balance at December 31, 2018		1,445			11			2,639			4,095
PROVED DEVELOPED RESERVES
December 31, 2015		813			19			1,872			2,704
December 31, 2016		708			6			2,324			3,038
December 31, 2017		782			11			2,131			2,924
December 31, 2018 (d)		978			11			2,015			3,004
PROVED UNDEVELOPED RESERVES (e)
December 31, 2015		206			—			458			664
December 31, 2016		337			—			399			736
December 31, 2017		423			1			483			907
December 31, 2018		467			—			624			1,091

(a)	Approximately one-third of proved reserve amounts relate to PSCs and other similar economic arrangements.

(b)	Revisions of previous estimates in 2018 primarily reflected positive revisions in Al Hosn Gas due to improved performance partially offset by negative price revisions at Dolphin. Revisions of previous estimates in 2017 primarily reflected positive domestic revisions. Revisions of previous estimates in 2016 primarily reflected positive revisions in Al Hosn Gas.

(c)	Sales of proved reserves in 2018 were related to the sale of non-core Permian acreage. Sales of proved reserves in 2017 were primarily related to the sale of South Texas and non-core acreage in the Permian Basin. 2016 sales of proved reserves are related to Piceance.

(d)	Approximately 3 percent of the proved developed reserves at December 31, 2018, are nonproducing, primarily associated with Permian Basin.

(e)

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.

(Unaudited)

Total Reserves
in millions of BOE (MMBOE) (a)
		United			Latin			Middle
		States			America			East			Total (b)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2015		1,271			80			849			2,200
Revisions of previous estimates (c)		(92	)		3			248			159
Improved recovery		165			2			18			185
Extensions and discoveries		—			—			2			2
Purchases of proved reserves		137			—			—			137
Sales of proved reserves (d)		(18	)		—			(28	)		(46	)
Production		(110	)		(13	)		(108	)		(231	)
Balance at December 31, 2016		1,353			72			981			2,406
Revisions of previous estimates (c)		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 (d)		(44	)		—			—			(44	)
Production		(111	)		(12	)		(97	)		(220	)
Balance at December 31, 2017		1,555			84			959			2,598
Revisions of previous estimates (c)		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 (d)		(17	)		—			—			(17	)
Production		(136	)		(11	)		(93	)		(240	)
Balance at December 31, 2018		1,711			98			943			2,752
PROVED DEVELOPED RESERVES
December 31, 2015		950			80			702			1,732
December 31, 2016		937			70			849			1,856
December 31, 2017		1,063			79			786			1,928
December 31, 2018 (e)		1,202			79			721			2,002
PROVED UNDEVELOPED RESERVES (f)
December 31, 2015		321			—			147			468
December 31, 2016		416			2			132			550
December 31, 2017		492			5			173			670
December 31, 2018		509			19			222			750

(a)

Natural gas volumes have been converted to barrels of oil equivalent (BOE) based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2018, the average daily prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $64.77 per barrel and $2.97 per Mcf, respectively, resulting in an oil to gas ratio of over 20 to 1.

(b)	Included proved reserves related to PSCs and other similar economic arrangements of 0.3 billion BOE, 0.5 billion BOE, 0.5 billion BOE, and 0.5 billion BOE at December 31, 2018, 2017, 2016 and 2015, respectively.

(c)

Revisions of previous estimates in 2018 primarily reflected positive revisions in Permian Basin related to prices and Al Hosn Gas due to improved performance. Revisions of previous estimates in 2017 reflected positive revisions in the Permian Basin and Oman. Revisions in 2016 are primarily positive revisions in Al Hosn Gas and price revisions in Oman due to the PSC impact, partially offset by negative domestic price revisions.

(d)	Sales of proved reserves in 2018 were primarily related to the sale of non-core acreage in the Permian Basin. Sales of proved reserves in 2017 were primarily related to the sale of South Texas and non-core acreage in the Permian Basin. 2016 sales of proved reserves are related to Libya and Piceance.

(e)	Approximately 9 percent of the proved developed reserves at December 31, 2018, are nonproducing, primarily associated with Oman and Permian EOR.

(f)

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.

(Unaudited)

CAPITALIZED COSTS

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

		United				Latin				Middle
in millions		States				America				East				Total
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
December 31, 2016
Proved properties		$	32,220			$	3,029			$	16,453			$	51,702
Unproved properties		2,548				28				393				2,969
Total capitalized costs (a)		34,768				3,057				16,846				54,671
Proved properties depreciation, depletion and amortization		(15,085		)		(2,285		)		(13,067		)		(30,437		)
Unproved properties valuation		(1,178		)		(27		)		—				(1,205		)
Total Accumulated depreciation, depletion and amortization		(16,263		)		(2,312		)		(13,067		)		(31,642		)
Net capitalized costs		$	18,505			$	745			$	3,779			$	23,029

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

COSTS INCURRED

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

		United				Latin				Middle
in millions		States				America				East				Total
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
FOR THE YEAR ENDED DECEMBER 31, 2016
Property acquisition costs
Proved properties		$	797			$	—			$	28			$	825
Unproved properties		1,265				—				339				1,604
Exploration costs		13				6				52				71
Development costs		1,417				75				670				2,162
Costs incurred		$	3,492			$	81			$	1,089			$	4,662

(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:

		United				Latin				Middle
in millions		States				America				East				Total
FOR THE YEAR ENDED DECEMBER 31, 2018
Revenues (a)		$	5,747			$	731			$	3,963			$	10,441
Production costs (b)		1,686				154				1,037				2,877
Other operating expenses		672				49				186				907
Depreciation, depletion and amortization		2,321				102				831				3,254
Taxes other than on income		407				6				—				413
Exploration expenses		64				19				27				110
Pretax income before impairments and related items		597				401				1,882				2,880
Asset impairments and related items		32				—				416				448
Pretax income		565				401				1,466				2,432
Income tax expense (benefit) (c)		(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
Production costs (b)		1,474				155				950				2,579
Other operating expenses		585				51				166				802
Depreciation, depletion and amortization		2,549				124				596				3,269
Taxes other than on income		273				9				—				282
Exploration expenses		28				7				47				82
Pretax income (loss) before impairments and related items		(862		)		224				1,494				856
Asset impairments and related items		397				4				—				401
Pretax income (loss)		(1,259		)		220				1,494				455
Income tax expense (benefit) (c)		(695		)		120				690				115
Results of operations		$	(564	)		$	100			$	804			$	340
FOR THE YEAR ENDED DECEMBER 31, 2016
Revenues (a)		$	3,135			$	476			$	2,766			$	6,377
Production costs (b)		1,335				170				982				2,487
Other operating expenses		426				36				218				680
Depreciation, depletion and amortization		2,793				156				626				3,575
Taxes other than on income		240				10				—				250
Exploration expenses		8				5				49				62
Pretax income (loss) before impairments and related items		(1,667		)		99				891				(677		)
Asset impairments and related items		1				9				61				71
Pretax income (loss)		(1,668		)		90				830				(748		)
Income tax expense (benefit) (c)		(784		)		65				336				(383		)
Results of operations		$	(884	)		$	25			$	494			$	(365	)

(a)	Revenues are net of royalty payments.

(b)	Production costs are the costs incurred in lifting the oil and gas to the surface and include gathering, primary processing and field storage, but do not include DD&A, royalties, income taxes, interest, general and administrative and other expenses.

(c)	U.S. federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead. These amounts are computed using the statutory rate in effect during the period.

(Unaudited)

RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

		United				Latin				Middle
$/BOE (a)		States				America				East				Total
FOR THE YEAR ENDED DECEMBER 31, 2018
Revenues (b)		$	42.30			$	63.37			$	42.78			$	43.50
Production costs		12.41				13.32				11.20				11.98
Other operating expenses		4.95				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
Pretax income before impairments and related items		4.39				34.76				20.32				11.99
Asset impairments and related items		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
Production costs		13.29				12.99				9.79				11.73
Other operating expenses		5.28				4.28				1.71				3.65
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
Pretax income (loss) before impairments and related items		(7.78		)		18.81				15.39				3.89
Asset impairments and related items		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
FOR THE YEAR ENDED DECEMBER 31, 2016
Revenues (b)		$	28.36			$	36.87			$	25.67			$	27.59
Production costs		12.07				13.16				9.12				10.76
Other operating expenses		3.86				2.76				2.02				2.94
Depreciation, depletion and amortization		25.27				12.12				5.81				15.46
Taxes other than on income		2.17				0.77				—				1.08
Exploration expenses		0.07				0.39				0.45				0.27
Pretax income (loss) before impairments and related items		(15.08		)		7.67				8.27				(2.92		)
Asset impairments and related items		0.01				0.70				0.57				0.31
Pretax income (loss)		(15.09		)		6.97				7.70				(3.23		)
Income tax expense (benefit) (c)		(7.09		)		5.03				3.12				(1.66		)
Results of operations		$	(8.00	)		$	1.94			$	4.58			$	(1.57	)

(a)

Natural gas volumes have been converted to barrels of oil equivalent (BOE) based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2018, the average daily prices of WTI oil and NYMEX natural gas were $64.77 per barrel and $2.97 per Mcf, respectively, resulting in an oil to gas ratio of over 20 to 1.

(b)	Revenues are net of royalty payments.

(c)	United States federal income taxes reflect certain expenses related to oil and gas activities allocated for U.S. income tax purposes only, including allocated interest and corporate overhead. These amounts are computed using the statutory rate in effect during the period, and do not consider the effects of changes to the U.S. federal income tax law by Tax Reform.

(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, 2018, 2017 and 2016, respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. For the 2018, 2017 and 2016 disclosures, the calculated average West Texas Intermediate oil prices were $65.56, $51.34 and $42.75 per barrel, respectively. The calculated average Brent oil prices for 2018, 2017 and 2016 disclosures were $72.20, $54.93 and $44.49, per barrel, respectively. The calculated average Henry Hub natural gas prices for 2018, 2017 and 2016 were $3.10, $3.08, and $2.55 per MMBtu, respectively. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities to develop and produce proved reserves at year end. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10 percent discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2018, 2017 and 2016. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

Standardized Measure of Discounted Future Net Cash Flows
in millions
		United				Latin				Middle
		States				America				East				Total
AT DECEMBER 31, 2018
Future cash inflows		$	75,313			$	6,104			$	31,158			$	112,575
Future costs
Production costs and other operating expenses		(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
Ten percent 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 expenses		(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
Ten percent discount factor		(10,951		)		(423		)		(5,026		)		(16,400		)
Standardized measure of discounted future net cash flows		$	9,196			$	842			$	6,182			$	16,220
AT DECEMBER 31, 2016
Future cash inflows		$	42,289			$	2,551			$	21,079			$	65,919
Future costs
Production costs and other operating expenses		(23,574		)		(1,418		)		(8,101		)		(33,093		)
Development costs (a)		(7,204		)		(134		)		(1,900		)		(9,238		)
Future income tax expense		—				(244		)		(2,349		)		(2,593		)
Future net cash flows		11,511				755				8,729				20,995
Ten percent discount factor		(6,676		)		(202		)		(4,404		)		(11,282		)
Standardized measure of discounted future net cash flows		$	4,835			$	553			$	4,325			$	9,713

(a)	Includes asset retirement costs.

(Unaudited)

Changes in the Standardized Measure of Discounted Future
Net Cash Flows From Proved Reserve Quantities
in millions
For the years ended December 31,		2018				2017				2016
Beginning of year		$	16,220			$	9,713			$	11,395
Sales and transfers of oil and gas produced, net of production costs and other operating expenses		(7,828		)		(5,362		)		(3,830		)
Net change in prices received per barrel, net of production costs and other operating expenses		9,482				7,598				(3,714		)
Extensions, discoveries and improved recovery, net of future production and development costs		3,378				1,534				811
Change in estimated future development costs		(3,463		)		(1,283		)		(227		)
Revisions of quantity estimates		664				966				868
Previously estimated development costs incurred during the period		1,943				1,643				1,662
Accretion of discount		1,551				922				1,034
Net change in income taxes		(1,182		)		(528		)		1,367
Purchases and sales of reserves in place, net		347				688				178
Changes in production rates and other		2,349				329				169
Net change		7,241				6,507				(1,682		)
End of year		$	23,461			$	16,220			$	9,713

Average Sales Prices

The following table sets forth, for each of the three years in the period ended December 31, 2018, Occidental’s approximate average sales prices in continuing operations.

						United				Latin				Middle
						States				America				East				Total
2018
Oil		—		Average sales price ($/bbl)		$	56.30			$	64.32			$	67.69			$	60.64
NGL		—		Average sales price ($/bbl)		$	27.64			$	—			$	23.20			$	26.25
Gas		—		Average sales price ($/mcf)		$	1.59			$	6.43			$	1.58			$	1.62
2017
Oil		—		Average sales price ($/bbl)		$	47.91			$	48.50			$	50.38			$	48.93
NGL		—		Average sales price ($/bbl)		$	23.67			$	—			$	18.05			$	21.63
Gas		—		Average sales price ($/mcf)		$	2.31			$	5.08			$	1.52			$	1.84
2016
Oil		—		Average sales price ($/bbl)		$	39.38			$	37.48			$	38.25			$	38.73
NGL		—		Average sales price ($/bbl)		$	14.72			$	—			$	15.01			$	14.82
Gas		—		Average sales price ($/mcf)		$	1.90			$	3.78			$	1.27			$	1.53

(Unaudited)

Net Productive and Dry — Exploratory and Development Wells Completed

The following table sets forth, for each of the three years in the period ended December 31, 2018, Occidental’s net productive and dry exploratory and development wells completed.

						United			Latin			Middle
						States			America			East			Total
2018
Oil		—		Exploratory		11			2			5			18
				Development		267			54			138			459
Gas		—		Exploratory		—			—			—			—
				Development		3			—			1			4
Dry		—		Exploratory		—			2			3			5
				Development		—			—			—			—
2017
Oil		—		Exploratory		14			1			5			20
				Development		201			51			105			357
Gas		—		Exploratory		—			—			—			—
				Development		2			—			1			3
Dry		—		Exploratory		—			—			3			3
				Development		—			—			—			—
2016
Oil		—		Exploratory		—			—			2			2
				Development		166			12			157			335
Gas		—		Exploratory		—			—			—			—
				Development		—			—			10			10
Dry		—		Exploratory		—			—			6			6
				Development		—			—			—			—

Productive Oil and Gas Wells

The following table sets forth, as of December 31, 2018, Occidental’s productive oil and gas wells (both producing and capable of production).

Wells at December 31, 2018 (a)						United States						Latin America						Middle East						Total
Oil		—		Gross (b)		16,674			(886	)		1,857			—			2,595			(1	)		21,126			(887	)
				Net (c)		14,501			(812	)		976			—			1,369			(1	)		16,846			(813	)
Gas		—		Gross (b)		2,606			(319	)		33			—			112			—			2,751			(319	)
				Net (c)		2,312			(299	)		31			—			59			—			2,402			(299	)

(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.

(Unaudited)

Participation in Exploratory and Development Wells Being Drilled

The following table sets forth, as of December 31, 2018, Occidental’s participation in exploratory and development wells being drilled.

Wells at December 31, 2018						United States			Latin America			Middle East			Total
Exploratory and development wells
		—		Gross		52			3			21			76
		—		Net		52			2			13			67

At December 31, 2018, Occidental was participating in 88 pressure-maintenance projects, mostly waterfloods, in the United States, five in Latin America and 24 in the Middle East.

Oil and Gas Acreage

The following table sets forth, as of December 31, 2018, Occidental’s holdings of developed and undeveloped oil and gas acreage.

Thousands of acres at						United			Latin			Middle
December 31, 2018						States			America			East			Total
Developed (a)
		—		Gross (b)		6,026			145			678			6,849
		—		Net (c)		3,030			99			286			3,415
Undeveloped (d)
		—		Gross (b)		1,652			481			5,815			7,948
		—		Net (c)		537			310			4,900			5,747

(a)	Acres spaced or assigned to productive wells.

(b)	Total acres in which interests are held.

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

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

Occidental’s investment in developed and undeveloped acreage comprises numerous concessions, blocks and leases. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before 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.

(Unaudited)

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

The following tables set forth the production and sales volumes of oil, NGL and natural gas per day for each of the three years in the period ended December 31, 2018. The differences between the production and sales volumes per day are generally due to the timing of shipments at Occidental’s international locations where product is loaded onto tankers.

Production per Day (MBOE)		2018			2017			2016
United States
Permian Resources		214			141			124
Permian EOR		154			150			145
Other Domestic		4			13			33
Total		372			304			302
Latin America		32			32			34
Middle East
Al Hosn Gas		73			71			64
Dolphin		40			42			43
Oman		86			95			96
Qatar		55			58			65
Other		—			—			26
Total		254			266			294
Total Production (MBOE) (a)		658			602			630
(See footnote following the Sales Volumes from Ongoing Operations table)

Production per Day from Ongoing Operations (MBOE)		2018			2017			2016
United States
Permian Resources		214			141			124
Permian EOR		154			150			145
Other Domestic		4			5			4
Total		372			296			273
Latin America		32			32			34
Middle East
Al Hosn Gas		73			71			64
Dolphin		40			42			43
Oman		86			95			96
Qatar		55			58			65
Total		254			266			268
Total Production Ongoing Operations (MBOE) (a)		658			594			575
Sold domestic operations		—			8			29
Sold or Exited MENA operations		—			—			26
Total Production (MBOE) (a)		658			602			630
(See footnote following the Sales Volumes from Ongoing Operations table)

(Unaudited)

Production per Day by Products		2018			2017			2016
United States
Oil (MBBL)
Permian Resources		132			85			77
Permian EOR		117			113			108
Other Domestic		1			2			4
Total		250			200			189
NGL (MBBL)
Permian Resources		38			26			21
Permian EOR		29			27			27
Other Domestic		—			2			5
Total		67			55			53
Natural gas (MMCF)
Permian Resources		261			184			158
Permian EOR		50			57			59
Other Domestic		16			53			144
Total		327			294			361
Latin America
Oil (MBBL)		31			31			33
Natural gas (MMCF)		6			7			8
Middle East
Oil (MBBL)
Al Hosn Gas		13			13			12
Dolphin		7			7			7
Oman		63			71			77
Qatar		55			59			65
Other		—			—			7
Total		138			150			168
NGL (MBBL)
Al Hosn Gas		23			23			20
Dolphin		8			8			8
Total		31			31			28
Natural gas (MMCF)
Al Hosn Gas		220			211			190
Dolphin		152			159			166
Oman		139			138			115
Other		—			—			114
Total		511			508			585
Total Production (MBOE) (a)		658			602			630
(See footnote following the Sales Volumes from Ongoing Operations table)

(Unaudited)

Production per Day by Products from Ongoing Operations		2018			2017			2016
United States
Oil (MBBL)
Permian Resources		132			85			77
Permian EOR		117			113			108
Other Domestic		1			2			1
Total		250			200			186
NGL (MBBL)
Permian Resources		38			26			21
Permian EOR		29			27			27
Total		67			53			48
Natural gas (MMCF)
Permian Resources		261			184			158
Permian EOR		50			57			59
Other Domestic		16			18			18
Total		327			259			235
Latin America
Oil (MBBL)		31			31			33
Natural gas (MMCF)		6			7			8
Middle East
Oil (MBBL)
Al Hosn Gas		13			13			12
Dolphin		7			7			7
Oman		63			71			77
Qatar		55			59			65
Total		138			150			161
NGL (MBBL)
Al Hosn Gas		23			23			20
Dolphin		8			8			8
Total		31			31			28
Natural gas (MMCF)
Al Hosn Gas		220			211			190
Dolphin		152			159			166
Oman		139			138			115
Total		511			508			471
Total Production Ongoing Operations (MBOE) (a)		658			594			575
Sold domestic operations		—			8			29
Sold or Exited MENA operations		—			—			26
Total Production (MBOE) (a)		658			602			630
(See footnote following the Sales Volumes from Ongoing Operations table)

(Unaudited)

Sales Volumes per Day by Products		2018			2017			2016
United States								.
Oil (MBBL)		250			200			189
NGL (MBBL)		67			55			53
Natural gas (MMCF)		327			294			361
Latin America
Oil (MBBL)		31			32			34
Natural gas (MMCF)		6			7			8
Middle East
Oil (MBBL)
Al Hosn Gas		13			13			12
Dolphin		7			7			7
Oman		63			72			77
Qatar		55			58			66
Other		—			—			7
Total		138			150			169
NGL (MBBL)
Al Hosn Gas		23			23			20
Dolphin		8			8			8
Total		31			31			28
Natural gas (MMCF)		511			508			585
Total Sales Volumes (MBOE) (a)		658			603			632
(See footnote following the Sales Volumes from Ongoing Operations table)

Sales Volumes per Day by Products from Ongoing Operations		2018			2017			2016
United States
Oil (MBBL)		250			200			186
NGL (MBBL)		67			53			48
Natural gas (MMCF)		327			259			235
Latin America
Oil (MBBL)		31			32			34
Natural gas (MMCF)		6			7			8
Middle East
Oil (MBBL)
Al Hosn Gas		13			13			12
Dolphin		7			7			7
Oman		63			72			77
Qatar		55			58			66
Total		138			150			162
NGL (MBBL)
Al Hosn Gas		23			23			20
Dolphin		8			8			8
Total		31			31			28
Natural gas (MMCF)		511			508			471
Total Sales Ongoing Operations (MBOE) (a)		658			595			577
Sold domestic operations		—			8			29
Sold or Exited MENA operations		—			—			26
Total Sales Volumes (MBOE) (a)		658			603			632

(a)

Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2018, the average daily prices of WTI oil and NYMEX natural gas were $64.77 per barrel and $2.97, respectively, resulting in an oil to gas ratio of over 20 to 1.

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

						Additions
		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions (a)				Balance at End of Period
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)
2016
Allowance for doubtful accounts		$	20			$	543			$	(3	)		$	(2	)		$	558		(b)
Environmental, litigation, tax and other reserves		$	479			$	61			$	531			$	(74	)		$	997		(c)

Note: The amounts presented represent continuing operations.

(a)	Primarily represents payments.

(b)	Of these amounts, $24 million, $18 million and $17 million in 2018, 2017 and 2016, respectively, are classified as current.

(c)	Of these amounts, $146 million, $163 million and $197 million in 2018, 2017 and 2016, respectively, are classified as current.