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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, 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, 2017, 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 23, 2018 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.

/s/ KPMG LLP

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

Houston, Texas

February 23, 2018

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, 2017, 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, 2017, 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, 2017 and 2016, 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, 2017, and the related notes and financial statement schedule II - valuation and qualifying accounts (collectively, the “consolidated financial statements’’), and our report dated February 23, 2018 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 23, 2018

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

Assets at December 31,		2017				2016
CURRENT ASSETS
Cash and cash equivalents		$	1,672			$	2,233
Trade receivables, net of reserves of $16 in 2017 and $16 in 2016		4,145				3,989
Inventories		1,246				866
Assets held for sale		474				—
Other current assets		733				1,340
Total current assets		8,270				8,428
INVESTMENTS
Investment in unconsolidated entities		1,515				1,401
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment		53,409				54,673
Chemical segment		6,847				6,930
Midstream and marketing		9,493				9,216
Corporate		497				474
		70,246				71,293
Accumulated depreciation, depletion and amortization		(39,072		)		(38,956		)
		31,174				32,337
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET		1,067				943
TOTAL ASSETS		$	42,026			$	43,109

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,		2017				2016
CURRENT LIABILITIES
Current maturities of long-term debt		$	500			$	—
Accounts payable		4,408				3,926
Accrued liabilities		2,492				2,436
Total current liabilities		7,400				6,362
LONG-TERM DEBT, NET		9,328				9,819
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes		581				1,132
Asset retirement obligations		1,241				1,245
Pension and postretirement obligations		1,005				963
Environmental remediation reserves		728				739
Other		1,171				1,352
		4,726				5,431
STOCKHOLDERS' EQUITY
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, issued shares: 2017 — 893,468,707 and 2016 — 892,214,604		179				178
Treasury stock: 2017 — 128,364,195 shares and 2016 — 127,977,306 shares		(9,168		)		(9,143		)
Additional paid-in capital		7,884				7,747
Retained earnings		21,935				22,981
Accumulated other comprehensive loss		(258		)		(266		)
Total stockholders' equity		20,572				21,497
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	42,026			$	43,109

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,		2017				2016				2015
REVENUES AND OTHER INCOME
Net sales		$	12,508			$	10,090			$	12,480
Interest, dividends and other income		99				106				118
Gains on sale of equity investments and other assets		667				202				101
		13,274				10,398				12,699
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion, and amortization of $4,000 in 2017, $4,266 in 2016, and $4,540 in 2015)		5,594				5,189				5,804
Selling, general and administrative and other operating expenses		1,424				1,330				1,270
Depreciation, depletion and amortization		4,002				4,268				4,544
Asset impairments and related items		545				825				10,239
Taxes other than on income		311				277				343
Exploration expense		82				62				36
Interest and debt expense, net		345				292				147
		12,303				12,243				22,383
INCOME (LOSS) BEFORE INCOME TAXES AND OTHER ITEMS		971				(1,845		)		(9,684		)
(Provision for) benefit from domestic and foreign income taxes		(17		)		662				1,330
Income from equity investments		357				181				208
INCOME (LOSS) FROM CONTINUING OPERATIONS		1,311				(1,002		)		(8,146		)
Income from discontinued operations		—				428				317
NET INCOME (LOSS)		$	1,311			$	(574	)		$	(7,829	)
BASIC EARNINGS (LOSS) PER COMMON SHARE (attributable to common stock)
Income (loss) from continuing operations		$	1.71			$	(1.31	)		$	(10.64	)
Discontinued operations, net		—				0.56				0.41
BASIC EARNINGS (LOSS) PER COMMON SHARE		$	1.71			$	(0.75	)		$	(10.23	)
DILUTED EARNINGS (LOSS) PER COMMON SHARE (attributable to common stock)
Income (loss) from continuing operations		$	1.70			$	(1.31	)		$	(10.64	)
Discontinued operations, net		—				0.56				0.41
DILUTED EARNINGS (LOSS) PER COMMON SHARE		$	1.70			$	(0.75	)		$	(10.23	)
DIVIDENDS PER COMMON SHARE		$	3.06			$	3.02			$	2.97
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,		2017				2016				2015
Net income (loss) attributable to common stock		$	1,311			$	(574	)		$	(7,829	)
Other comprehensive income (loss) items:
Foreign currency translation (losses) gains		3				—				(2		)
Unrealized gains (losses) on derivatives (a)		13				(14		)		3
Pension and postretirement gains (losses) (b)		(7		)		47				48
Reclassification of realized losses (gains) on derivatives (c)		(1		)		8				1
Other comprehensive income, net of tax		8				41				50
Comprehensive income (loss)		$	1,319			$	(533	)		$	(7,779	)

(a)	Net of tax of $(7), $8 and $(2) in 2017, 2016 and 2015, respectively. The 2015 amount includes a lower of cost or market inventory adjustment for hedged natural gas of $(2).

(b)	Net of tax of $4, $(26) and $(27) in 2017, 2016 and 2015, respectively. See Note 13 for additional information.

(c)	Net of tax of zero, $(4) and $(1) in 2017, 2016 and 2015, 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 Income (Loss)				Total Equity
Balance, December 31, 2014		$	178			$	(8,528	)		$	7,599			$	36,067			$	(357	)		$	34,959
Net loss		—				—				—				(7,829		)		—				(7,829		)
Other comprehensive income, net of tax		—				—				—				—				50				50
Dividends on common stock		—				—				—				(2,278		)		—				(2,278		)
Issuance of common stock and other, net		—				—				41				—				—				41
Purchases of treasury stock		—				(593		)		—				—				—				(593		)
Balance, December 31, 2015		$	178			$	(9,121	)		$	7,640			$	25,960			$	(307	)		$	24,350
Net loss		—				—				—				(574		)		—				(574		)
Other comprehensive income, net of tax		—				—				—				—				41				41
Dividends on common stock		—				—				—				(2,405		)		—				(2,405		)
Issuance of common stock and other, net		—				—				107				—				—				107
Purchases of treasury stock		—				(22		)		—				—				—				(22		)
Balance, December 31, 2016		$	178			$	(9,143	)		$	7,747			$	22,981			$	(266	)		$	21,497
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

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,		2017				2016				2015
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)		$	1,311			$	(574	)		$	(7,829	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Income from discontinued operations		—				(428		)		(317		)
Depreciation, depletion and amortization of assets		4,002				4,268				4,544
Deferred income tax benefit		(719		)		(517		)		(1,372		)
Other noncash charges to income		222				121				159
Asset impairments and related items		545				665				9,684
Gain on sale of equity investments and other assets		(667		)		(202		)		(101		)
Undistributed earnings from equity investments		(68		)		3				6
Dry hole expenses		51				33				10
Changes in operating assets and liabilities:
Decrease (increase) in receivables		(158		)		(1,091		)		1,431
Decrease (increase) in inventories		(349		)		17				(24		)
Decrease in other current assets		39				65				33
(Decrease) increase in accounts payable and accrued liabilities		43				603				(1,989		)
(Decrease) increase in current domestic and foreign income taxes		64				17				(331		)
Other operating, net		680				(461		)		(650		)
Operating cash flow from continuing operations		4,996				2,519				3,254
Operating cash flow from discontinued operations, net of taxes		—				864				97
Net cash provided by operating activities		4,996				3,383				3,351
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(3,599		)		(2,717		)		(5,272		)
Change in capital accrual		122				(114		)		(592		)
Payments for purchases of assets and businesses		(1,064		)		(2,044		)		(109		)
Sales of equity investments and assets, net		1,403				302				819
Other, net		(76		)		(169		)		(269		)
Net cash used by investing activities		(3,214		)		(4,742		)		(5,423		)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt		—				4,203				1,478
Payments of long-term debt		—				(2,710		)		—
Change in restricted cash		—				1,193				2,826
Proceeds from issuance of common stock		28				36				37
Purchases of treasury stock		(25		)		(22		)		(593		)
Cash dividends paid		(2,346		)		(2,309		)		(2,264		)
Net cash provided (used) by financing activities		(2,343		)		391				1,484
Decrease in cash and cash equivalents		(561		)		(968		)		(588		)
Cash and cash equivalents — beginning of year		2,233				3,201				3,789
Cash and cash equivalents — end of year		$	1,672			$	2,233			$	3,201

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 (NGLs) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO2) and power. It also trades around its assets, including transportation and storage capacity. Additionally, the midstream and marketing segment operates a crude oil export terminal, as well as 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 2017 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.

REVENUE RECOGNITION

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

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

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

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

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with GAAP requires Occidental's management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements. Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets 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 $9.8 billion as of December 31, 2017, and net sales of approximately $4.4 billion for the year ended December 31, 2017, 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 $1.3 billion and $2.0 billion at December 31, 2017, and 2016, respectively.

RESTRICTED CASH

Restricted cash was the result of the separation of California Resources in 2014. As of December 31, 2017, there was no restricted cash.

INVESTMENTS

Available-for-sale securities are recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income/loss (AOCI). Trading securities are recorded at fair value with unrealized and realized gains or losses included in net sales.

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

INVENTORIES

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

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

PROPERTY, PLANT AND EQUIPMENT

Oil and Gas

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. Asset retirement obligations and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.

Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, Occidental capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. Otherwise, Occidental charges the costs of the related wells to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Occidental generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

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

in millions		2017				2016				2015
Balance — Beginning of Year		$	56			$	76			$	141
Additions to capitalized exploratory well costs pending the determination of proved reserves		201				29				88
Reclassifications to property, plant and equipment based on the determination of proved reserves		(128		)		(28		)		(78		)
Capitalized exploratory well costs charged to expense		(21		)		(21		)		(75		)
Balance — End of Year		$	108			$	56			$	76

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 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 15 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 and $1.4 billion at December 31, 2017, and 2016, respectively. 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 fifty years, are also used for impairment tests. The estimated useful lives for the chemical facilities are based on the assumption that Occidental will provide an appropriate level of annual expenditures to ensure productive capacity is sustained. Such expenditures consist of ongoing routine repairs and maintenance, as well as planned major maintenance activities (PMMA). Ongoing routine repairs and maintenance expenditures are expensed as incurred. PMMA costs are capitalized and amortized over the period until the next planned overhaul. Additionally, Occidental incurs capital expenditures that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add value through modification for a different use. These capital expenditures are not considered in the initial determination of the useful lives of these assets at the time they are placed into service. The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for prospectively.

Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.

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

Midstream and Marketing

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

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

IMPAIRMENTS AND RELATED ITEMS

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 recorded net impairment and related charges of $61 million related to the sale of Libya and exit from Iraq and the termination of crude oil supply contracts at a cost of $160 million. The corporate amount included an allowance for doubtful accounts. The allowance for doubtful accounts recorded during 2016 includes a reserve against the long-term receivable related to environmental sites indemnified by Maxus described in Note 8. Occidental recorded a reserve against this receivable due to the uncertainty of collection as a result of the Maxus bankruptcy.

In 2015, Occidental recorded impairment and related charges on oil and gas assets due to the decline in oil and gas prices, the decision to sell or exit non-core assets and changes in development plans for its non-producing assets. In November 2015, Occidental sold its Williston Basin assets in North Dakota and in December 2015, Occidental entered into an agreement to sell its Piceance Basin operations in Colorado. In Iraq, Occidental issued a notice of withdrawal and reassigned its interest in the Zubair Field in accordance with the contract terms. In Bahrain, Occidental issued a notice of withdrawal, reassigning its interest, and completed the exit in 2016. In Yemen, Occidental’s non-operated interest in Block 10 East Shabwa Field expired in December 2015, and in February 2016, Occidental sold its interests in Block S-1, An Nagyah Field.

In 2015, the midstream and marketing segment recorded an impairment charge for the Century gas processing plant as a result of our partner's inability to provide volumes to the plant and meet its contractual obligations to deliver CO2.

For the years ended December 31, (in millions)		2017				2016				2015
OIL AND GAS
United States
Impairments and related charges of exiting operations		$	—			$	(44	)		$	1,862		(a)
Impairments related to decline in commodity prices and changes in future development plans		397				15				1,428
Rig termination charges		—				—				192
Other asset impairment related charges		—				5				204
Latin America
Impairments related to decline in commodity prices and other		4				9				559
Middle East and North Africa
Impairments of exiting operations		—				61				1,658
Impairments related to decline in commodity prices		—				—				2,833
CHEMICAL
Impairments of assets		—				—				121
MIDSTREAM AND MARKETING
Century gas processing plant		—				—				814
Other asset impairment related charges		120				160				216
CORPORATE
Other-than-temporary impairment of investment in California Resources		—				78				227
Severance, spin-off and allowance for doubtful accounts		—				541				125
		$	521			$	825			$	10,239

(a)	A portion of the 2015 charges are reported in the Midstream and Marketing segment.

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 include accrued payroll, commissions and related expenses of $412 million and $341 million at December 31, 2017, and 2016, 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 $1.2 billion is included in deferred credits and other liabilities - asset retirement obligations, with the remaining current portion in accrued liabilities at both December 31, 2017, and 2016.

For the years ended December 31, (in millions)		2017				2016
Beginning balance		$	1,369			$	1,124
Liabilities incurred – capitalized to PP&E		46				46
Liabilities settled and paid		(39		)		(38		)
Accretion expense		67				59
Acquisitions, dispositions and other – changes in PP&E		(136		)		11
Revisions to estimated cash flows – changes in PP&E		5				167
Ending balance		$	1,312			$	1,369

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, 2017, 2016 and 2015.

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 forecasted transaction is no longer deemed probable.

STOCK-BASED INCENTIVE PLANS

Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more fully described in Note 12. A summary of Occidental’s accounting policy for awards issued under the Plans is as follows.

For cash- and stock-settled restricted stock units or incentive award shares (RSU) and capital employed incentive awards and return on assets (ROCEI/ROAI), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout at the grant date. For total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from a Monte Carlo valuation model. Compensation expense for RSUs, ROCEI/ROAI and TSRIs is recognized on a straight-line basis over the requisite service periods, which is generally over the awards’ respective vesting or performance periods. Compensation expense for the dividends accrued on unvested awards is adjusted quarterly for any changes in stock price and the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable. All such performance or stock-price-related changes are recognized in periodic compensation expense. The stock-settled portion of these awards is expensed using the initially measured compensation value.

EARNINGS PER SHARE

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

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

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans, which are more fully described in Note 13, in its financial statements using a December 31 measurement date.

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

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

SUPPLEMENTAL CASH FLOW INFORMATION

Occidental paid United States federal, state and foreign income taxes for continuing operations of approximately $0.8 billion, $0.6 billion and $1 billion during the years ended December 31, 2017, 2016 and 2015, respectively. Occidental received refunds of $0.8 billion and $0.3 billion during the years ended December 31, 2017, and 2016, respectively. Occidental also paid production, property and other taxes of approximately $375 million, $345 million and $445 million during the years ended December 31, 2017, 2016 and 2015, respectively, substantially all of which was in the United States. Interest paid totaled $351 million, $312 million and $246 million, net of capitalized interest of $52 million, $64 million and $138 million, for the years 2017, 2016 and 2015, respectively.

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s foreign 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

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 Occidental'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 $0.4 billion of 2.6-percent senior notes due 2022, $1.15 billion of 3.4-percent senior notes due 2026 and $1.2 billion of 4.4-percent senior notes due 2046. Occidental received net proceeds of approximately $2.72 billion. Interest on the senior notes is payable semi-annually in arrears in April and October of each year for each series of senior notes, beginning on October 15, 2016. Occidental used a portion of the proceeds to retire debt in May and June 2016, and used the remaining proceeds for general corporate purposes.

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

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

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

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

2015

In January 2016, Occidental reached an understanding on the terms of payment for the approximate $1.0 billion payable to Occidental by the Republic of Ecuador under a November 2015 International Center for the Settlement of Investment Disputes arbitration award. This award relates to Ecuador's 2006 expropriation of Occidental's Participation Contract for Block 15. As of December 31, 2015, Occidental recorded a pre-tax gain of $322 million. The result of this settlement with Ecuador has been presented as discontinued operations.

In December 2015, Occidental entered a sales agreement to sell its Piceance Basin operations in Colorado for approximately $155 million. The transaction was completed in March 2016. As a result of exiting the Piceance Basin operations Occidental recorded certain contractual liabilities which are included in deferred credits and other liabilities - other on the consolidated balance sheet. The assets and liabilities related to these operations are presented as held for sale at December 31, 2015 and primarily included property, plant and equipment and current accrued liabilities and asset retirement obligations.

In November 2015, Occidental sold its Williston Basin assets in North Dakota for approximately $590 million.

In October 2015, Occidental completed the sale of its Westwood building in Los Angeles, California for net proceeds of $65 million.

In June 2015, Occidental issued $1.5 billion of debt that was comprised of $750 million of 3.50-percent senior unsecured notes due 2025 and $750 million of 4.625-percent senior unsecured notes due 2045. Occidental received net proceeds of approximately $1.48 billion. Interest on the notes is payable semi-annually in arrears in June and December of each year for both series of notes, beginning on December 15, 2015.

NOTE 3	ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

In August 2017, the Financial Accounting Standards Board ("FASB") released targeted improvements to hedge accounting standards that will expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company's risk management activities. These rules also decrease the cost and complexity of hedge accounting. The new rules are effective for fiscal years beginning after December 15, 2018. Occidental is currently evaluating the effect of the new rules on its hedges.

In March 2017, FASB issued guidance related to presentation of net periodic pension cost and net periodic postretirement benefit cost. The rules become effective for annual periods beginning after December 15, 2017. These rules are not expected to have a material impact to Occidental's financial statements upon adoption.

In January 2017, the FASB issued new guidance clarifying the definition of a business under the topic Business Combinations. The new rules are effective for fiscal years beginning after December 15, 2017, and are not expected to have a material change on 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 become effective for the interim and annual periods beginning after December 15, 2017 and must be applied retrospectively. Occidental did not have restricted cash as of December 31, 2017 or 2016.

In October 2016, the FASB issued new guidance related to the income tax consequences of intra-entity transfers of assets other than inventory. The rules become effective for the interim and annual periods beginning after December 15, 2017. The rules do not have a material impact on Occidental's financial statements upon adoption.

In August 2016, the FASB issued new guidance related to the classification of certain cash receipts and payments on the statement of cash flows. The rules become effective for the interim and annual periods beginning after December 15, 2017. The rules will be adopted for the first quarter of 2018 and will result in the retrospective reclassification of certain cash receipts and payments within the Statement of Cash Flows.

In 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard Topic 606 - Revenue from Contracts with Customers, previously issued in May 2014. Under the new standard, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. Occidental will adopt the standard using the modified retrospective approach and recognize a cumulative effect adjustment to Retained Earnings as of January 1, 2018. The cumulative-effect adjustment to retained earnings upon adoption is not material. Occidental stratified all revenue streams within each operating segment and compiled an inventory of all contracts from which a sample of customer contracts was reviewed to assess the required accounting under the new standard The review consisted of identifying whether such contracts are in scope of the new standard; whether there will be material changes in the timing or amount of revenue recognized from our historical accounting policies and practices; whether processes and controls are in place to evaluate new contracts for revenue recognition and to assemble any additional required disclosures. Occidental has reviewed and considered interpretations and published guidelines from The Entities with Oil and Gas Producing Activities Revenue Recognition Task Force of the American Institute of Certified Public Accountants and certain public accounting firms, respectively. Occidental has completed its review of the sample contracts and does not expect any material change to the pattern or timing of revenue recognition and earnings as a result of adopting the new standard. Additionally, Occidental has assessed the disclosure requirements under the new standard and anticipates disclosing additional information, as necessary, to supplement the historical disaggregated revenue disclosures, including qualitative disclosures regarding the nature of its customer contracts and performance obligations. Occidental is coordinating the data collection needs to meet those disclosure requirements. Occidental continues to conduct training for accounting staff on the new standard.

In February 2016, the FASB issued rules which require Occidental to recognize most leases, including operating leases, on the balance sheet. The new rules require lessees to recognize a right-of-use asset and lease liability for all leases with lease terms of more than 12 months. The lease liability represents the discounted obligation to make future minimum lease payments. 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. The guidance retains the current accounting for lessors and does not make significant changes to the recognition, measurement and presentation of expenses and cash flows by a lessee. Recognition, measurement and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. Occidental is the lessee under various agreements for real estate, equipment, plants and facilities, aircraft, information technology hardware and vehicles that are currently accounted for as operating leases, refer to Note 6. As a result, these new rules will increase reported assets and liabilities. Occidental will not be an early adopter of this standard. Occidental will apply the revised lease rules for its interim and annual reporting periods starting January 1, 2019, using a modified retrospective approach, including several optional practical expedients related to leases commenced before the effective date. Occidental is currently evaluating the effect of these rules on its financial statements, training accounting staff and developing an internal interim software solution for the identification, documentation and tracking of leases in order to create an adoption plan based on Occidental's population of leases under the revised definition of leases. The quantitative impacts of the new standard are

dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standard will extend over future periods.

NOTE 4	INVENTORIES

Net carrying values of inventories valued under the LIFO method were approximately $172 million and $192 million at December 31, 2017 and 2016, respectively. Finished goods primarily represents crude oil, caustic soda and chlorine. Inventories consisted of the following:

Balance at December 31, (in millions)		2017				2016
Raw materials		$	66			$	65
Materials and supplies		447				446
Finished goods		776				395
		1,289				906
Revaluation to LIFO		(43		)		(40		)
Total		$	1,246			$	866

NOTE 5	LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)		2017				2016
1.50% senior notes due 2018		$	500			$	500
9.25% senior debentures due 2019		116				116
4.10% senior notes due 2021		1,249				1,249
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
Variable rate bonds due 2030 (1.8% and 0.9% as of December 31, 2017 and 2016, respectively )		68				68
		9,907				9,907
Less:
Unamortized discount, net		(32		)		(36		)
Debt issuance costs		(47		)		(52		)
Current maturities		(500		)		—
Total		$	9,328			$	9,819

As of December 31, 2017, Occidental had an undrawn $2.0 billion revolving credit facility (2014 Credit Facility). Occidental did not draw down any amounts under the 2014 Credit Facility during 2017 or 2016, and no amounts were outstanding as of December 31, 2017. Borrowings under the 2014 Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental paid average annual facility fees of 0.08 percent in 2017 on the total commitment amounts of the 2014 Credit Facility. In January 2018, Occidental entered into a new five-year, $3.0 billion revolving credit facility (2018 Credit Facility) which replaced the 2014 Credit Facility, which was scheduled to expire in August 2019. The 2018 Credit Facility has similar terms to the 2014 Credit Facility and along with other debt agreements does not contain material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow or that would permit lenders to terminate their commitments or accelerate debt. 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. The 2018 Credit Facility matures in January 2023.

As of December 31, 2017, 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, 2017, and 2016, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on approximately $272 million and $296 million, respectively, of Dolphin’s debt. The fair value of the guarantees was immaterial.

At December 31, 2017, principal payments on long-term debt aggregated approximately $9.9 billion, of which $0.5 billion is due in 2018, $0.1 billion is due in 2019, zero is due in 2020, $1.3 billion is due in 2021, $1.2 billion is due in 2022, and $6.8 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, 2017, and 2016, substantially all of which were classified as Level 1, were approximately $10.4 billion and $10.2 billion, respectively, compared to carrying values of approximately $9.9 billion at December 31, 2017 and 2016. 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, 2017, and 2016, variable-rate debt constituted approximately one percent of Occidental's total debt.

NOTE 6	LEASE COMMITMENTS

Operating lease agreements include leases for transportation equipment, power plants, machinery, terminals, storage facilities, land and office space. Occidental’s operating lease agreements frequently include renewal or purchase options and require the Company to pay for utilities, taxes, insurance and maintenance expenses. At December 31, 2017, future net minimum lease payments for noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:

(in millions)		Amount
2018		$	275
2019		135
2020		99
2021		87
2022		85
Thereafter		387
Total minimum lease payments		$	1,068

Rental expense for operating leases was $278 million in 2017, $237 million in 2016 and $197 million in 2015.

NOTE 7	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

2017. As of December 31, 2017, and 2016, Occidental had approximately 7 billion cubic feet (Bcf) of natural gas held in storage, and had cash-flow hedges for the forecasted sales, to be settled by physical delivery, of approximately 7 Bcf of stored natural gas. The amount of cash-flow hedges, including the ineffective portion, was immaterial for the years ended December 31, 2017 and 2016.

Derivatives Not Designated as Hedging Instruments

The following table summarizes the amounts reported in net sales related to the outstanding commodity derivative instruments not designated as hedging instruments as of December 31, 2017, and 2016:

As of December 31, (in millions, except Long/(Short) volumes)		2017				2016
Unrealized gain (loss) on derivatives not designated as hedges
Oil commodity contracts		$	(47	)		$	(5	)
Natural gas commodity contracts		$	1			$	1
Outstanding net volumes on derivatives not designated as hedges
Oil Commodity Contracts
Volume (MMBOE)		61				67
Price Per Bbl		$	57.38			$	53.86
Natural gas commodity contracts
Volume (Bcf)		(47		)		(12		)
Price Per MMBTU		$	2.73			$	3.19

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, 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 $53 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.

As of December 31, 2016				Fair Value Measurements Using									Netting (b)			Total Fair Value
(in millions)		Balance Sheet Location		Level 1			Level 2			Level 3
Assets:
Cash-flow hedges (a)
Commodity contracts		Other current assets		—			1			—			—			1
	Long-term receivables and other assets, net		—			—			—			—			—
Derivatives not designated as hedging instruments (a)
Commodity contracts		Other current assets		166			57			—			(196	)		27
	Long-term receivables and other assets, net		2			3			—			(2	)		3
Liabilities:
Cash-flow hedges (a)
Commodity contracts		Accrued liabilities		—			6			—			—			6
	Deferred credits and liabilities		—			—			—			—			—
Derivatives not designated as hedging instruments (a)
Commodity contracts		Accrued liabilities		172			51			—			(196	)		27
	Deferred credits and liabilities		1			6			—			(2	)		5

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

(b)

These amounts do not include collateral. As of December 31, 2016, collateral received of $4 million has been netted against derivative assets and collateral paid of $13 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 $25 million as of December 31, 2016, deposited by Occidental, has not been reflected in these derivative fair value tables. This collateral is included in other current assets in the consolidated balance 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, 2017, and 2016. 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, 2017, and December 31, 2016.

NOTE 8	ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations related to improving or maintaining environmental quality.

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

ENVIRONMENTAL REMEDIATION

As of December 31, 2017, Occidental participated in or monitored remedial activities or proceedings at 148 sites. The following table presents Occidental’s current and non-current environmental remediation reserves as of December 31, 2017, 2016 and 2015, the current portion of which is included in accrued liabilities ($137 million in 2017, $131 million in 2016, and

$70 million in 2015) and the remainder in deferred credits and other liabilities — environmental remediation reserves ($728 million in 2017, $739 million in 2016, and $316 million in 2015). 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)		2017							2016							2015
		Number of Sites			Reserve Balance				Number of Sites			Reserve Balance				Number of Sites			Reserve Balance
NPL sites		34			$	457			33			$	461			34			$	27
Third-party sites		70			157				68			163				66			128
Occidental-operated sites		15			108				17			106				18			107
Closed or non-operated Occidental sites		29			143				29			140				31			124
Total		148			$	865			147			$	870			149			$	386

As of December 31, 2017, Occidental’s environmental reserves exceeded $10 million each at 16 of the 148 sites described above, and 89 of the sites had reserves from $0 to $1 million each.

As of December 31, 2017, 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 95 percent of its reserves associated with NPL sites. The reserve balance above includes 17 NPL sites indemnified by Maxus.

Five of the 70 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, a sediment site in Louisiana and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities accounted for 60 percent of Occidental’s reserves associated with these sites. The reserve balance above includes 9 third-party sites indemnified by Maxus.

Three sites — chemical plants in Kansas, Louisiana and Texas accounted for 49 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 California, and a closed coal mine in Pennsylvania accounted for 62 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 Energy Corporation (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 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.

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)		2017				2016				2015
Operating Expenses
Oil and Gas		$	68			$	65			$	93
Chemical		78				75				74
Midstream and Marketing		15				11				13
		$	161			$	151			$	180
Capital Expenditures
Oil and Gas		$	77			$	43			$	122
Chemical		18				25				41
Midstream and Marketing		6				5				4
		$	101			$	73			$	167
Remediation Expenses
Corporate		$	39			$	61			$	117

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

NOTE 9	LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

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 foreign environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties and injunctive relief. Usually Occidental or such subsidiaries are among many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound companies. Further, some lawsuits, claims and legal proceedings involve acquired or disposed assets with respect to which a third party or Occidental retains liability or indemnifies the other party for conditions that existed prior to the transaction.

In accordance with applicable accounting guidance, Occidental accrues reserves for outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. In Note 8, 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, 2017 and December 31, 2016, were not material to Occidental's consolidated balance sheet.

In 2017, Andes Petroleum Ecuador Ltd. filed a demand for arbitration, claiming it is entitled to a 40 percent share of the settlement payments made by the Republic of Ecuador to Occidental for the 2006 expropriation of Occidental’s Participation Contract for Ecuador’s Block 15. Occidental intends to vigorously defend against this claim in arbitration.

The ultimate outcome and impact of outstanding lawsuits, claims and proceedings on Occidental cannot be predicted. Management believes that the resolution of these matters will not, individually or in the aggregate, have a material adverse effect on Occidental's consolidated balance sheet, statements of operations or cash flows after consideration of recorded accruals. 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. Although taxable years through 2009 for United States federal income tax purposes have been audited by the United States Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program, subsequent taxable years are currently under review. Taxable years from 2002 through the current year remain subject to

examination by foreign and state government tax authorities in certain jurisdictions. In certain of these jurisdictions, tax authorities are in various stages of auditing Occidental’s income taxes. During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law. Occidental believes that the resolution of outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.

Indemnities to Third Parties

Occidental, its subsidiaries, or both, have indemnified various parties against specified liabilities those parties might incur in the future in connection with purchases and other transactions that they have entered into with Occidental. These indemnities usually are contingent upon the other party incurring liabilities that reach specified thresholds. As of December 31, 2017, 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, 2017, total purchase obligations were $8.1 billion, which included approximately $1.6 billion, $1.2 billion, $0.9 billion, $0.7 billion and $0.6 billion that will be paid in 2018, 2019, 2020, 2021 and 2022, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2018 and thereafter, which were approximately $0.7 billion.

NOTE 10	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
2017		$	(609	)		$	1,937			$	1,328
2016		$	(2,698	)		$	1,034			$	(1,664	)
2015		$	(5,810	)		$	(3,666	)		$	(9,476	)

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
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	)
2015
Current		$	(810	)		$	(31	)		$	883			$	42
Deferred		(1,146		)		(83		)		(143		)		(1,372		)
		$	(1,956	)		$	(114	)		$	740			$	(1,330	)

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,		2017			2016			2015
United States federal statutory tax rate		35	%		35	%		35	%
Other than temporary loss on available for sale investment in California Resources stock		—			(2	)		(1	)
Enhanced oil recovery credit		(9	)		5			—
Tax benefit due to write off of exploration blocks		—			14			—
Change in federal income tax rate		(44	)		—			—
Tax expense due to reversal of indefinite reinvestment assertion		7			—			—
Operations outside the United States		12			(14	)		(21	)
State income taxes, net of federal benefit		2			—			1
Other		(2	)		2			—
Worldwide effective tax rate		1	%		40	%		14	%

On December 22, 2017, the 2017 Tax Cuts and Jobs Act (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 foreign corporations. In accordance with the guidance from the SEC, Occidental recorded a provisional estimate for the federal and state income tax associated with the mandatory deemed repatriation and the resulting impact to the net federal deferred tax liability. Tax Reform introduced a new tax on certain foreign income which the statute refers to as global intangible low-tax income (GILTI). GILTI is income of a U.S.-owned foreign corporation (net of allowed deductions) in excess of a 10 percent rate of return on the assets of the subsidiary. Tax Reform also introduced a base-erosion anti-abuse tax (BEAT) that aims to reduce the ability of multinational companies to use cross-border payments to shift income to affiliates in lower-taxed countries. Based on current analysis and interpretation of Tax Reform, Occidental does not anticipate a material GILTI or BEAT-related tax obligation and is recording no current or deferred tax impact with regards to GILTI or BEAT on a provisional basis. Further, pending definitive technical guidance from the states in which it is subject to income tax, Occidental has recorded a reasonable estimate of $10 million for the state tax associated with the mandatory deemed repatriation on a provisional basis. The ultimate impact of Tax Reform may differ from Occidental’s estimates due to changes in interpretations and assumptions, as well as additional regulatory guidance. Occidental will adjust provisional amounts as updated information is evaluated.

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2017, and 2016 were as follows:

		2017								2016
Tax effects of temporary differences (in millions)		Deferred Tax Assets				Deferred Tax Liabilities				Deferred Tax Assets				Deferred Tax Liabilities
Property, plant and equipment differences		$	—			$	2,272			$	—			$	3,345
Equity investments, partnerships and foreign subsidiaries		—				134				—				58
Environmental reserves		191				—				314				—
Postretirement benefit accruals		145				—				342				—
Deferred compensation and benefits		151				—				222				—
Asset retirement obligations		228				—				406				—
Foreign tax credit carryforwards		2,750				—				2,046				—
Corporate alternative minimum tax credit carryforwards		—				—				226				—
General business credit carryforwards		407				—				186				—
Net operating loss carryforward		437				—				—				—
Federal benefit of state income taxes		10				—				8				—
All other		146				—				370				—
Subtotal		4,465				2,406				4,120				3,403
Valuation allowance		(2,640		)		—				(1,849		)		—
Total deferred taxes		$	1,825			$	2,406			$	2,271			$	3,403

Total deferred tax assets, after valuation allowances, were $1.8 billion and $2.3 billion as of December 31, 2017, and 2016, respectively. Occidental expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences. The reduction in the net deferred tax liabilities is primarily related to

the reduction in the federal corporate income tax rate from 35 percent to 21 percent and the addition of $221 million of general business credits to the credit carryforward balance.

Occidental had, as of December 31, 2017, foreign tax credit carryforwards of $2.8 billion, which expire in varying amounts through 2027, $35 million of state operating loss carryforwards, which have varying carryforward periods through 2037, $402 million of federal operating loss carryforwards that expire in 2037, and $407 million of general business credit carryforwards that expire between 2033 and 2037. Occidental had, as of December 31, 2017, corporate AMT carryforwards of $221 million, that have been classified as non-current receivables due to Tax Reform. At December 31, 2017, Occidental reversed its indefinite re-investment assertion with regards to its investments in foreign subsidiaries and, as a result, a deferred foreign tax liability of $99 million was recorded. Occidental's valuation allowance provides for substantially all of the foreign tax credit carryforwards and approximately $4 million of the state net operating loss carryforwards.

Discontinued operations include income tax charges of $249 million and $1 million in 2016, and 2015, respectively.

As of December 31, 2017, Occidental had liabilities for unrecognized tax benefits of approximately $22 million included in deferred credits and other liabilities – other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.

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

For the years ended December 31, (in millions)		2017				2016				2015
Balance at January 1,		$	22			$	22			$	61
Reductions based on tax positions related to prior years and settlements		—				—				(39		)
Balance at December 31,		$	22			$	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 $76 million and $761 million in income tax receivables at December 31, 2017, and 2016, respectively, which were recorded in other current assets.

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

Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes and these amounts were not material for the years ended December 31, 2017, 2016 and 2015.

NOTE 11	STOCKHOLDERS' EQUITY

The following is a summary of common stock issuances:

Shares in thousands		Common Stock
Balance, December 31, 2014		890,558
Issued		782
Options exercised and other, net		20
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

TREASURY STOCK

On October 2, 2014, Occidental increased the total number of shares authorized for its share repurchase program by 60 million shares to 185 million shares total; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time. No shares were purchased under the program in 2017 and 2016. In 2015, Occidental purchased 7.4 million shares under the program at an average cost of $76.99 per share. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year. As of December 31, 2017, 2016 and 2015, treasury stock shares numbered 128.4 million, 128.0 million and 127.7 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, 2017, 2016 and 2015, Occidental had no outstanding shares of preferred stock.

EARNINGS PER SHARE

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

(in millions, except per-share amounts)		2017				2016				2015
Income (loss) from continuing operations		$	1,311			$	(1,002	)		$	(8,146	)
Income (loss) from continuing operations attributable to common stock		1,311				(1,002		)		(8,146		)
Income from discontinued operations		—				428				317
Net income (loss)		1,311				(574		)		(7,829		)
Less: Net income allocated to participating securities		(6		)		—				—
Net income (loss), net of participating securities		$	1,305			$	(574	)		$	(7,829	)
Weighted average number of basic shares		765.1				763.8				765.6
Basic earnings (loss) per common share		$	1.71			$	(0.75	)		$	(10.23	)
Net income (loss), net of participating securities		$	1,305			$	(574	)		$	(7,829	)
Weighted average number of basic shares		765.1				763.8				765.6
Dilutive securities		0.8				—				—
Total diluted weighted average common shares		765.9				763.8				765.6
Diluted earnings (loss) per common share		$	1.70			$	(0.75	)		$	(10.23	)

ACCUMULATED OTHER COMPREHENSIVE LOSS

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

Balance at December 31, (in millions)		2017				2016
Foreign currency translation adjustments		$	(7	)		$	(10	)
Unrealized losses on derivatives		—				(13		)
Pension and postretirement adjustments (a)		(251		)		(243		)
Total		$	(258	)		$	(266	)

(a)	See Note 13 for further information.

NOTE 12	STOCK-BASED INCENTIVE PLANS

Occidental has established several plans that allow it to issue stock-based awards including in the form of RSUs, stock options (Options), stock appreciation rights (SARs), ROCEI/ROAI and TSRIs. An aggregate of 35 million shares of Occidental common stock were authorized for issuance and approximately 6.1 million shares had been allocated to employee awards through December 31, 2017. In accordance with the terms of the shareholder approved 2015 Long-Term Incentive Plan (LTIP), awards issued under the superseded 2005 LTIP and subsequently forfeited after adoption of the 2015 LTIP increase the shares available for issuance under the 2015 LTIP. As of December 31, 2017, approximately 27.7 million shares were available for grants of future awards. The plan requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the number of shares that are available for future awards. Accordingly, the number of shares available for future awards may be less than 27.7 million depending on the type of award granted. Additionally, under the plan, the shares available for future awards may increase, depending on the award type, by the number of shares currently unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or canceled, or (iii) correspond to the portion of any stock-based awards settled in cash, including awards that were issued under a previous plan that remain outstanding.

During 2017, non-employee directors were granted awards for 32,787 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.

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

For the years ended December 31, (in millions)		2017				2016				2015
Compensation expense		$	150			$	121			$	49
Income tax benefit recognized in the income statement		32				43				17

As of December 31, 2017, unrecognized compensation expense for all unvested stock-based incentive awards was $214 million. This expense is expected to be recognized over a weighted-average period of 1.7 years.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs are settled in cash or stock at the time of vesting. These awards vest from one to four years following the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied by the seventh anniversary of the grant date. For certain 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 2017, 2016 and 2015 were $66.62, $75.57, and $72.64 per share, respectively. The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2017, 2016, and 2015 were $67.21, $74.82, and $72.54, respectively. Cash-Settled RSUs resulted in payments of $22.5 million, $41 million, and $39 million during the years ended December 31, 2017, 2016 and 2015, respectively. The fair value of RSUs settled in shares during the years ended December 31, 2017, 2016 and 2015 was $64 million, $31 million, and $28 million, respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2017 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		601				$	78.70				3,500				$	77.07
Granted		62				66.62					1,683				67.21
Vested		(373	)			81.94					(1,064	)			76.51
Forfeitures		(21	)			76.72					(168	)			71.86
Unvested at December 31		269				$	71.58				3,951				$	73.24

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 total shareholder return performance relative to its peers and the S&P 500. 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, 2017, 2016 and 2015 was $5 million, $8 million, and $14 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		2017				2016				2015
Assumptions used:
Risk-free interest rate		1.5		%		0.8		%		0.9		%
Dividend yield		4.5		%		3.9		%		4.1		%
Volatility factor		25		%		24		%		37		%
Expected life (years)		3				3				3
Grant-date fair value of underlying Occidental common stock		$	67.21			$	76.83			$	72.54

A summary of Occidental’s unvested TSRIs as of December 31, 2017, and changes during the year ended December 31, 2017, is presented below:

		TSRIs
		Awards (000’s)			Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1		707				$	78.72
Granted		601				67.21
Vested (a)		(98	)			96.75
Forfeitures		(58	)			70.75
Unvested at December 31		1,152				71.58

(a)	Presented at the target payouts.The payout at vesting was 84% of the target.

STOCK OPTIONS AND SARs

Certain employees have been granted Stock Appreciation Rights (SAR) or 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 2017. The intrinsic value of options and stock-settled SARs exercised during the years ended December 31, 2017, 2016, and 2015 was zero, $1 million, and zero, respectively.

The fair value of each Option or stock-settled SAR 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 and SAR transactions during the year ended December 31, 2017:

		SARs & Options (000's)			Weighted-Average Exercise Price				Weighted-Average Remaining Contractual Term (yrs)			Aggregate Intrinsic Value (000’s)
Beginning balance, January 1		571			$	79.98
Forfeited		(22	)		79.98
Ending balance, December 31		549			79.98				4.1			$	—
Exercisable at December 31		397			79.98				4.1			$	—

ROCEI / ROAI

Occidental grants share-equivalents to certain employees that vest at the end of a three-year period if performance targets based on return on assets of the applicable segment or return on capital employed are certified as being met. These awards are settled in stock 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.

		ROCEI / ROAI
		Awards (000's)			Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1		392				$	85.43
Vested (a)		(124	)			87.52
Unvested at December 31		268				84.46

(a)	Presented at the target payouts.The payout at vesting was 53% of the target for approximately 6,000 shares. The payout at vesting was 0% of target for the remaining 118,000 shares.

NOTE 13	RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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

DEFINED CONTRIBUTION PLANS

All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, 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 $175 million and $163 million as of December 31, 2017 and 2016, respectively, and Occidental expensed $130 million in 2017, $113 million in 2016 and $136 million in 2015 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited and approximately 500 domestic and 900 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 $181 million in 2017, $182 million in 2016 and $200 million in 2015.

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,		2017				2016				2017				2016
Amounts recognized in the consolidated balance sheet:
Other assets		$	82			$	61			$	—			$	—
Accrued liabilities		(5		)		(3		)		(59		)		(58		)
Deferred credits and other liabilities — pension and postretirement obligations		(65		)		(71		)		(940		)		(892		)
		$	12			$	(13	)		$	(999	)		$	(950	)
AOCI included the following after-tax balances:
Net loss		$	59			$	76			$	192			$	169
Prior service cost		—				—				1				1
		$	59			$	76			$	193			$	170

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,		2017				2016				2017				2016
Changes in the benefit obligation:
Benefit obligation — beginning of year		$	399			$	411			$	950			$	979
Service cost — benefits earned during the period		6				7				21				20
Interest cost on projected benefit obligation		17				18				38				39
Actuarial (gain) loss		14				(1		)		61				(28		)
Foreign currency exchange rate (gain) loss		—				1				—				—
Liability (gain) loss due to curtailment		(2		)		—				(9		)		—
Special termination benefits		1				—				—				—
Benefits paid		(44		)		(37		)		(62		)		(60		)
Settlements		—				—				—				—
Benefit obligation — end of year		$	391			$	399			$	999			$	950
Changes in plan assets:
Fair value of plan assets — beginning of year		$	386			$	384			$	—			$	—
Actual return on plan assets		52				34				—				—
Foreign currency exchange rate loss		—				—				—				—
Employer contributions		9				5				—				—
Benefits paid		(44		)		(37		)		—				—
Settlements		—				—				—				—
Fair value of plan assets — end of year		$	403			$	386			$	—			$	—
Funded/(Unfunded) status:		$	12			$	(13	)		$	(999	)		$	(950	)

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,		2017				2016				2017				2016
Projected Benefit Obligation		$	287			$	193			$	104			$	206
Accumulated Benefit Obligation		$	283			$	189			$	104			$	206
Fair Value of Plan Assets		$	312			$	119			$	91			$	267

Occidental does not expect any plan assets to be returned during 2018.

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)		2017				2016				2015				2017				2016				2015
Net periodic benefit costs:
Service cost — benefits earned during the period		$	6			$	7			$	7			$	21			$	20			$	26
Interest cost on projected benefit obligation		17				18				18				38				39				40
Expected return on plan assets		(24		)		(24		)		(27		)		—				—				—
Recognized actuarial loss		10				12				10				14				15				27
Other costs and adjustments		3				4				(4		)		1				—				1
Net periodic benefit cost		$	12			$	17			$	4			$	74			$	74			$	94

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $5 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 $17 million and $1 million, respectively.

ADDITIONAL INFORMATION

The following table sets forth the weighted-average assumptions used to determine Occidental's benefit obligation and net periodic benefit cost for domestic plans:

		Pension Benefits						Postretirement Benefits
For the years ended December 31,		2017			2016			2017			2016
Benefit Obligation Assumptions:
Discount rate		3.45	%		3.90	%		3.61	%		4.15	%
Net Periodic Benefit Cost Assumptions:
Discount rate		3.90	%		4.14	%		4.15	%		4.36	%
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 2017 and 2016. 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 2017, Occidental adopted the Society of Actuaries 2017 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-2016 scale released in 2016. 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 $2 million and $9 million in the pension and postretirement benefit obligation at December 31, 2017.

For pension plans outside the United States, Occidental based its discount rate on rates indicative of government or investment grade corporate debt in the applicable country, taking into account hyperinflationary environments when necessary. The discount rates used for the foreign pension plans ranged from 1.0 percent to 10.8 percent at December 31, 2017 and 2016. The average rate of increase in future compensation levels ranged from 1.0 percent to 8.0 percent in 2017, 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 projected at an assumed U.S. Consumer Price Index (CPI) increase of 1.97 percent as of December 31, 2017 and 2016. Since 1993, participants other than certain union employees have paid for all medical cost increases in excess of increases in the CPI. For those union employees, Occidental projected that health care cost trend rates would decrease from 8.00 percent in 2017 until they reach 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 $42 million or a reduction of $34 million, respectively, in the postretirement benefit obligation as of December 31, 2017. The annual service and interest costs would not be materially affected by these changes.

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

FAIR VALUE OF PENSION PLAN ASSETS

Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk. The investments are monitored by Occidental’s Pension and Retirement Trust and Investment Committee (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, 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

(in millions)		Fair Value Measurements at December 31, 2016, Using
Description		Level 1				Level 2				Level 3				Total
Asset Class:
U.S. government securities		$	13			$	—			$	—			$	13
Corporate bonds (a)		—				85				—				85
Common/collective trusts (b)		—				18				—				18
Mutual funds:
Bond funds		18				—				—				18
Blend funds		48				—				—				48
Common and preferred stocks (c)		178				—				—				178
Other		—				29				—				29
Total pension plan assets (d)		$	257			$	132			$	—			$	389

(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 $8 million and $3 million as of December 31, 2017 and 2016, respectively.

Occidental expects to contribute $5 million in cash to its defined benefit pension plans during 2018. 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
2018		$	47			$	60
2019		$	30			$	59
2020		$	30			$	59
2021		$	31			$	59
2022		$	30			$	58
2023 - 2027		$	181			$	286

NOTE 14	INVESTMENTS AND RELATED-PARTY TRANSACTIONS

EQUITY INVESTMENTS

As of December 31, 2017, and 2016, investments in unconsolidated entities comprised $1.5 billion and $1.4 billion of equity-method investments, respectively.

As of December 31, 2017, Occidental’s equity investments consisted mainly of an equity interest in Plains Pipeline, 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 $297 million, $224 million, and $438 million to Occidental in 2017, 2016 and 2015, respectively. As of December 31, 2017, cumulative undistributed earnings of equity-method investees since they were acquired was immaterial. As of December 31, 2017, Occidental's investments in equity investees exceeded the underlying equity in net assets by approximately $649 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)		2017				2016				2015
Revenues		$	1,252			$	1,238			$	1,050
Costs and expenses		973				1,043				827
Net income		$	279			$	195			$	223
As of December 31, (in millions)		2017				2016
Current assets		$	602			$	914
Non-current assets		$	2,072			$	3,605
Current liabilities		$	247			$	577
Long-term debt		$	1,174			$	1,957
Other non-current liabilities		$	66			$	159
Stockholders’ equity		$	1,187			$	1,826

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, NGLs, power, steam and chemicals from and sells oil, NGLs, natural gas, chemicals and power to certain of its equity investees and other related parties. During 2017, 2016 and 2015, 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)		2017				2016				2015
Sales (a)		$	636			$	602			$	555
Purchases (b)		$	387			$	7			$	26
Services		$	38			$	17			$	32
Advances and amounts due from		$	63			$	59			$	60
Amounts due to		$	45			$	—			$	5

(a)

In 2017, 2016 and 2015, sales of Occidental-produced oil and NGLs to Plains Pipeline affiliates accounted for 86 percent, 89 percent and 87 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, NGLs and transportation. Net margins associated with these marketing activities are negligible.

(b)	In 2017, purchases of ethylene from the Ingleside ethylene cracker accounted for 98 percent of related-party purchases.

NOTE 15	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, 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

(in millions)		Fair Value Measurements at December 31, 2016 Using														Netting and Collateral				Total Fair Value
Description				Level 1				Level 2				Level 3
Liabilities:
Embedded derivative		Accrued liabilities		$	—			$	43			$	—			$	—			$	43
	Deferred credits and liabilities		$	—			$	178			$	—			$	—			$	178

FAIR VALUES – NONRECURRING

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.

As a result of the sharp decline of the forward price curve during 2015, as well as the decision to sell or exit non-core operations, Occidental recognized approximately $6.5 billion in pre-tax impairment charges related to proved oil and gas properties. Internationally, Occidental recognized $4.7 billion in pre-tax impairment charges related to $1.8 billion in charges in Oman, $1.3 billion in Iraq and Libya, $1 billion in Qatar, and $550 million in Colombia and Bolivia. Domestically, Occidental recognized pre-tax impairment charges of approximately $763 million related to the sale of the Williston assets, $460 million for assets in the Piceance Basin and $554 million related to proved oil and gas properties in South Texas.

During 2015, Occidental recognized approximately $814 million in pre-tax impairment charges for a Midstream CO2 treatment plant related to recurring CO2 shortfalls and unpaid penalty fees and approximately $121 million pre-tax charges related to the impairments of Chemical assets.

The impairment tests, including the fair value estimation, incorporated a number of assumptions involving expectations of future cash flows. These assumptions included estimates of future product prices, which Occidental based on forward price curves and, where applicable, contractual prices, estimates of oil and gas reserves, estimates of future expected operating and development costs and a risk-adjusted discount rate of 8 to 20 percent. These properties were impacted by persistently worldwide low oil and natural gas prices and management's changing development plans. Occidental used the income approach to measure the fair value of these properties, using inputs categorized as Level 3 in the fair value hierarchy.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash and cash equivalents and other on-balance sheet financial instruments, other than fixed-rate debt, approximate fair value. See Note 5 for the fair value of Long-term Debt.

NOTE 16	INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental conducts its continuing operations through three segments: (1) Oil and gas; (2) Chemical; and (3) Midstream and marketing. The oil and gas segment explores for, develops and produces oil and condensate, NGLs, and natural gas. The chemical segment mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, CO2 and power. It also trades around its assets, including transportation and storage capacity. Additionally, the midstream and marketing segment operates a crude oil export terminal, as well as invests in entities that conduct similar activities.

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, 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
Year ended December 31, 2015
Net sales		$	8,304		(a)	$	3,945		(b)	$	891		(c)	$	(660	)		$	12,480
Pretax operating profit (loss)		$	(8,060	)	(d)	$	542		(i)	$	(1,194	)	(e)	$	(764	)	(f)	$	(9,476	)
Income taxes		—				—				—				1,330			(g)	1,330
Discontinued operations, net		$	—			—				—				317			(j)	317
Net income (loss) attributable to common stock		$	(8,060	)		$	542			$	(1,194	)		$	883			$	(7,829	)
Investments in unconsolidated entities		$	4			$	550			$	708			$	5			$	1,267
Property, plant and equipment additions, net (h)		$	4,485			$	271			$	611			$	42			$	5,409
Depreciation, depletion and amortization		$	3,886			$	371			$	249			$	38			$	4,544
Total assets		$	23,591			$	3,982			$	10,175			$	5,661			$	43,409
(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, 2017, 2016 and 2015.

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

		Basic Chemicals		Vinyls		Other Chemicals
Year ended December 31, 2017		57%		42%		1%
Year ended December 31, 2016		57%		40%		3%
Year ended December 31, 2015		56%		40%		4%

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

		Gas Processing		Power		Marketing, Transportation and other *
Year ended December 31, 2017		69%		28%		3%
Year ended December 31, 2016		92%		44%		(36)%
Year ended December 31, 2015		70%		31%		(1)%

• Revenue from all marketing activities is reported on a net basis.

(d)

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. The 2015 amount includes pre-tax charges of $5 billion for impairment of international oil and gas assets and related items and $3.5 billion for the impairment of domestic oil and gas assets and related items.

(e)	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. The 2015 amount includes pre-tax charges of $1.3 billion related to asset impairments and related items.

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

Benefit (Charge) (in millions)		2017				2016				2015
CORPORATE
Pre-tax operating profit (loss)
Asset sale losses		$	—			$	—			$	(8	)
Asset impairments and related items		—				(619		)		(235		)
Severance, spin-off and other		—				—				(118		)
		$	—			$	(619	)		$	(361	)
Income taxes
Tax effect of pre-tax and other adjustments *		$	392			$	424			$	1,903

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

(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. The 2015 amount includes the pre-tax charge of $121 million related to asset impairment partially offset by a $98 million gain on sale of an idled facility.

(j)	Includes discontinued operations from Ecuador.

GEOGRAPHIC AREAS

(in millions)		Net sales (a)												Property, plant and equipment, net
For the years ended December 31,		2017				2016				2015				2017				2016				2015
United States		$	8,085			$	6,290			$	7,479			$	22,863			$	24,004			$	23,265
Foreign
Oman		1,397				1,101				1,631				1,962				1,858				1,292
Qatar		1,394				1,206				1,449				1,236				1,299				1,354
Colombia		555				463				570				807				741				821
United Arab Emirates		808				664				477				4,241				4,373				4,484
Other Foreign		269				366				874				65				62				423
Total Foreign		4,423				3,800				5,001				8,311				8,333				8,374
Total		$	12,508			$	10,090			$	12,480			$	31,174			$	32,337			$	31,639

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

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		)
Income from continuing operations		117				507				190				497
Discontinued operations, net		—				—				—				—
Net income attributable to common stock		$	117			$	507			$	190			$	497
Basic earnings per common share
Income from continuing operations		$	0.15			$	0.66			$	0.25			$	0.65
Discontinued operations, net		—				—				—				—
Basic earnings per common share		$	0.15			$	0.66			$	0.25			$	0.65
Diluted earnings per common share
Income from continuing operations		$	0.15			$	0.66			$	0.25			$	0.65
Discontinued operations, net		—				—				—				—
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
Market price per common share
High		$	72.96			$	65.73			$	65.70			$	74.06
Low		$	61.01			$	57.20			$	57.84			$	63.47

(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 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.

2016 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		$	1,275			$	1,625			$	1,660			$	1,817
Chemical		890				908				988				970
Midstream and marketing		133				141				202				208
Eliminations		(175		)		(143		)		(202		)		(207		)
Net sales		$	2,123			$	2,531			$	2,648			$	2,788
Gross profit		$	(335	)		$	143			$	203			$	345
Segment earnings
Oil and gas		$	(485	)	(a)	$	(117	)		$	(51	)	(a)	$	17		(a)
Chemical		214			(b)	88				117				152
Midstream and marketing		(95		)		(58		)		(180		)	(c)	(48		)
		(366		)		(87		)		(114		)		121
Unallocated corporate items
Interest expense, net		(57		)		(84		)		(62		)		(72		)
Income taxes		203				96				30				333
Other		(140		)	(d)	(61		)		(92		)		(650		)	(d)
Income from continuing operations		(360		)		(136		)		(238		)		(268		)
Discontinued operations, net		438			(e)	(3		)		(3		)		(4		)
Net income (loss)		$	78			$	(139	)		$	(241	)		$	(272	)
Basic earnings per common share
Income (loss) from continuing operations		$	(0.47	)		$	(0.18	)		$	(0.31	)		$	(0.35	)
Discontinued operations, net		0.57				—				(0.01		)		(0.01		)
Basic earnings per common share		$	0.10			$	(0.18	)		$	(0.32	)		$	(0.36	)
Diluted earnings per common share
Income (loss) from continuing operations		$	(0.47	)		$	(0.18	)		$	(0.31	)		$	(0.35	)
Discontinued operations, net		0.57				—				(0.01		)		(0.01		)
Diluted earnings per common share		$	0.10			$	(0.18	)		$	(0.32	)		$	(0.36	)
Dividends per common share		$	0.75			$	0.75			$	0.76			$	0.76
Market price per common share
High		$	72.19			$	78.31			$	78.48			$	75.60
Low		$	58.24			$	66.94			$	67.83			$	64.37

(a)

Included pre-tax asset sale gains of $48 million in the first quarter related to the sale of domestic oil and gas properties, and $59 million in the third quarter related to the sale of South Texas oil and gas properties. Included pre-tax charges of $25 million in the first quarter, $61 million in the third quarter, $9 million in the fourth quarter and a $24 million gain in the fourth quarter related to oil and gas asset impairments, related items, and other.

(b)	Included first quarter pre-tax asset sale gain of $57 million from the sale of the Occidental Tower building in Dallas and a $31 million gain from the sale of a non-core specialty chemicals business.

(c)	Included third quarter pre-tax charges of $160 million related to the termination of crude oil supply contracts.

(d)	Included first quarter pre-tax charges of $78 million and fourth quarter pre-tax charges of $541 million related to a reserve against a long-term receivable from Maxus due the uncertainty of collection.

(e)	Included the gains related to the Ecuador settlement.

Supplemental Oil and Gas Information (Unaudited)

The following tables set forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of oil (including condensate), NGLs and natural gas and changes in such quantities. Proved oil, NGLs and natural gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGLs and natural gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs. For the 2017, 2016 and 2015 disclosures, the calculated average West Texas Intermediate oil prices were $51.34, $42.75 and $50.28 per barrel, respectively. The calculated average Brent oil prices for 2017, 2016 and 2015 disclosures were $54.93, $44.49 and $55.57, per barrel, respectively. The calculated average Henry Hub natural gas prices for 2017, 2016 and 2015 were $3.08, $2.55 and $2.66 per MMBtu, respectively. Reserves are stated net of applicable royalties. Estimated reserves include Occidental's economic interests under production-sharing contracts (PSCs) and other similar economic arrangements. In addition, discussions of oil and gas production or volumes, in general, refer to sales volumes unless the context requires or it is indicated otherwise.

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

(Unaudited)

Oil Reserves
in millions of barrels (MMbbl)
		United			Latin			Middle East/
		States			America			North Africa (a)			Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2014		1,273			92			405			1,770
Revisions of previous estimates (b)		(220	)		(10	)		22			(208	)
Improved recovery		81			8			12			101
Extensions and discoveries		—			—			2			2
Purchases of proved reserves		—			—			—			—
Sales of proved reserves (c)		(146	)		—			(51	)		(197	)
Production		(73	)		(13	)		(73	)		(159	)
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
PROVED DEVELOPED RESERVES
December 31, 2014		819			86			316			1,221
December 31, 2015		673			77			278			1,028
December 31, 2016		670			69			298			1,037
December 31, 2017 (d)		772			77			279			1,128
PROVED UNDEVELOPED RESERVES (e)
December 31, 2014		454			6			89			549
December 31, 2015		242			—			39			281
December 31, 2016		290			2			28			320
December 31, 2017		335			5			47			387

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

(b)	Revisions of previous estimates in 2017 primarily reflected positive revisions in Permian Basin and Oman. Revisions of previous estimates in 2016 and 2015 were primarily price and price-related.

(c)	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. Sales of proved reserves in 2015 were related to the sale of Williston and exit from Iraq.

(d)	Approximately 10 percent of the proved developed reserves at December 31, 2017, are nonproducing, primarily associated with 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)

NGLs Reserves
in millions of barrels (MMbbl)
		United			Latin			Middle East/
		States			America			North Africa			Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2014		222			—			140			362
Revisions of previous estimates (a)		(28	)		—			10			(18	)
Improved recovery		12			—			1			13
Extensions and discoveries		—			—			—			—
Purchases of proved reserves		—			—			—			—
Sales of proved reserves		—			—			—			—
Production		(20	)		—			(7	)		(27	)
Balance at December 31, 2015		186			—			144			330
Revisions of previous estimates (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, 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, December 31, 2017		247			—			198			445
PROVED DEVELOPED RESERVES
December 31, 2014		147			—			109			256
December 31, 2015		141			—			112			253
December 31, 2016		149			—			164			313
December 31, 2017 (c)		161			—			153			314
PROVED UNDEVELOPED RESERVES (d)
December 31, 2014		75			—			31			106
December 31, 2015		45			—			32			77
December 31, 2016		70			—			37			107
December 31, 2017		86			—			45			131

(a)	Revisions of previous estimates were primarily price and price-related.

(b)	Sales of proved reserves in 2017 were primarily related to the sale of South Texas.

(c)	Approximately 5 percent of the proved developed reserves at December 31, 2017, 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 East/
		States			America			North Africa (a)			Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance, December 31, 2014		1,714			27			2,386			4,127
Revisions of previous estimates (b)		(600	)		(4	)		64			(540	)
Improved recovery		123			—			64			187
Extensions and discoveries		—			—			17			17
Purchases of proved reserves		—			—			—			—
Sales of proved reserves (c)		(63	)		—			—			(63	)
Production		(155	)		(4	)		(201	)		(360	)
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
PROVED DEVELOPED RESERVES
December 31, 2014		1,128			26			1,915			3,069
December 31, 2015		813			19			1,872			2,704
December 31, 2016		708			6			2,324			3,038
December 31, 2017 (d)		782			11			2,131			2,924
PROVED UNDEVELOPED RESERVES (e)
December 31, 2014		586			1			471			1,058
December 31, 2015		206			—			458			664
December 31, 2016		337			—			399			736
December 31, 2017		423			1			483			907

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

(b)	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. Revisions of previous estimates in 2015 were primarily price and price-related.

(c)	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. Sales of proved reserves in 2015 were related to the sale of Williston.

(d)	Approximately 3 percent of the proved developed reserves at December 31, 2017, are nonproducing, primarily associated with the 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 East/
		States			America			North Africa			Total (b)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2014		1,781			96			942			2,819
Revisions of previous estimates (c)		(348	)		(10	)		43			(315	)
Improved recovery		113			8			23			144
Extensions and discoveries		—			—			5			5
Purchases of proved reserves		—			—			—			—
Sales of proved reserves (d)		(156	)		—			(51	)		(207	)
Production		(119	)		(14	)		(113	)		(246	)
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
PROVED DEVELOPED RESERVES
December 31, 2014		1,154			90			744			1,988
December 31, 2015		950			80			702			1,732
December 31, 2016		937			70			849			1,856
December 31, 2017 (e)		1,063			79			786			1,928
PROVED UNDEVELOPED RESERVES (f)
December 31, 2014		627			6			198			831
December 31, 2015		321			—			147			468
December 31, 2016		416			2			132			550
December 31, 2017		492			5			173			670

(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 2017, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $51.34 per barrel and $3.08 per Mcf, respectively, resulting in an oil to gas ratio of 17 to 1.

(b)	Included proved reserves related to PSCs and other similar economic arrangements of 0.5 billion BOE, 0.5 billion BOE, 0.5 billion BOE, and 0.7 billion BOE at December 31, 2017, 2016, 2015, and 2014, respectively.

(c)	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. Revisions of previous estimates in 2015 were primarily price and price related.

(d)	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. Sales of proved reserves in 2015 were related to the sale of Williston and exit from Iraq.

(e)	Approximately 7 percent of the proved developed reserves at December 31, 2017, are nonproducing, primarily associated with 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 East/
in millions		States				America				North Africa				Total
December 31, 2017
Proved properties		$	31,091			$	3,194			$	16,921			$	51,206
Unproved properties		2,094				53				55				2,202
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			$	16,792			$	52,041
Unproved properties		2,548				28				54				2,630
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
December 31, 2015
Proved properties		$	30,200			$	2,955			$	19,290			$	52,445
Unproved properties		1,376				27				1,077				2,480
Total capitalized costs (a)		31,576				2,982				20,367				54,925
Proved properties depreciation, depletion and amortization		(12,544		)		(2,119		)		(15,718		)		(30,381		)
Unproved properties valuation		(1,204		)		(27		)		(961		)		(2,192		)
Total Accumulated depreciation, depletion and amortization		(13,748		)		(2,146		)		(16,679		)		(32,573		)
Net capitalized costs		$	17,828			$	836			$	3,688			$	22,352

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

COSTS INCURRED

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

		United				Latin				Middle East/
in millions		States				America				North Africa				Total
FOR THE YEAR ENDED DECEMBER 31, 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			$	—			$	367			$	1,164
Unproved properties		1,265				—				—				1,265
Exploration costs		13				6				52				71
Development costs		1,417				75				670				2,162
Costs incurred		$	3,492			$	81			$	1,089			$	4,662
FOR THE YEAR ENDED DECEMBER 31, 2015
Property acquisition costs
Proved properties		$	37			$	—			$	47			$	84
Unproved properties		25				—				—				25
Exploration costs		74				2				66				142
Development costs		2,880				170				1,461				4,511
Costs incurred		$	3,016			$	172			$	1,574			$	4,762

(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 East/
in millions		States				America				North Africa				Total
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	)
FOR THE YEAR ENDED DECEMBER 31, 2015
Revenues (a)		$	3,809			$	589			$	3,906			$	8,304
Production costs (b)		1,571				160				1,113				2,844
Other operating expenses		511				29				238				778
Depreciation, depletion and amortization		2,109				196				1,581				3,886
Taxes other than on income		307				16				—				323
Exploration expenses		18				2				16				36
Pretax income (loss) before impairments and related items		(707		)		186				958				437
Asset impairments and related items		3,447				559				4,491				8,497
Pretax income (loss)		(4,154		)		(373		)		(3,533		)		(8,060		)
Income tax expense (benefit) (c)		(1,606		)		(61		)		787				(880		)
Results of operations		$	(2,548	)		$	(312	)		$	(4,320	)		$	(7,180	)

(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, and do not consider the effects of changes to the U.S. federal income tax law by Tax Reform.

(Unaudited)

RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

		United				Latin				Middle East/
$/BOE (a)		States				America				North Africa				Total
FOR THE YEAR ENDED DECEMBER 31, 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	)
FOR THE YEAR ENDED DECEMBER 31, 2015
Revenues (b)		$	31.84			$	43.83			$	34.64			$	33.78
Production costs		13.13				11.93				9.87				11.57
Other operating expenses		4.27				2.18				2.11				3.15
Depreciation, depletion and amortization		17.63				14.54				14.02				15.81
Taxes other than on income		2.57				1.19				—				1.32
Exploration expenses		0.15				0.15				0.14				0.15
Pretax income (loss) before impairments and related items		(5.91		)		13.84				8.50				1.78
Asset impairments and related items		28.81				41.60				39.82				34.56
Pretax income (loss)		(34.72		)		(27.76		)		(31.32		)		(32.78		)
Income tax expense (benefit) (c)		(13.42		)		(4.54		)		6.98				(3.58		)
Results of operations		$	(21.30	)		$	(23.22	)		$	(38.30	)		$	(29.20	)

(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 2017, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $51.34 per barrel and $3.08 per Mcf, respectively, resulting in an oil to gas ratio of 17 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, 2017, 2016 and 2015, respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. For the 2017, 2016 and 2015 disclosures, the calculated average West Texas Intermediate oil prices were $51.34, $42.75 and $50.28 per barrel, respectively. The calculated average Brent oil prices for 2017, 2016 and 2015 disclosures were $54.93, $44.49 and $55.57, per barrel, respectively. The calculated average Henry Hub natural gas prices for 2017, 2016 and 2015 were $3.08, $2.55 and $2.66 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, 2017, 2016 and 2015. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

Standardized Measure of Discounted Future Net Cash Flows
in millions
		United				Latin				Middle East/
		States				America				North Africa				Total
AT DECEMBER 31, 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
AT DECEMBER 31, 2015
Future cash inflows		$	47,290			$	3,416			$	22,994			$	73,700
Future costs
Production costs and other operating expenses		(25,386		)		(1,852		)		(9,041		)		(36,279		)
Development costs (a)		(7,245		)		(178		)		(2,672		)		(10,095		)
Future income tax expense		(759		)		(392		)		(4,045		)		(5,196		)
Future net cash flows		13,900				994				7,236				22,130
Ten percent discount factor		(7,446		)		(293		)		(2,996		)		(10,735		)
Standardized measure of discounted future net cash flows		$	6,454			$	701			$	4,240			$	11,395

(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,		2017				2016				2015
Beginning of year		$	9,713			$	11,395			$	30,149
Sales and transfers of oil and gas produced, net of production costs and other operating expenses		(5,362		)		(3,830		)		(4,952		)
Net change in prices received per barrel, net of production costs and other operating expenses		7,598				(3,714		)		(36,081		)
Extensions, discoveries and improved recovery, net of future production and development costs		1,534				811				854
Change in estimated future development costs		(1,283		)		(227		)		3,091
Revisions of quantity estimates		966				868				(1,782		)
Previously estimated development costs incurred during the period		1,643				1,662				3,327
Accretion of discount		922				1,034				3,220
Net change in income taxes		(528		)		1,367				13,046
Purchases and sales of reserves in place, net		688				178				(2,334		)
Changes in production rates and other		329				169				2,857
Net change		6,507				(1,682		)		(18,754		)
End of year		$	16,220			$	9,713			$	11,395

Average Sales Prices

The following table sets forth, for each of the three years in the period ended December 31, 2017, Occidental’s approximate average sales prices in continuing operations.

						United				Latin				Middle East/
						States				America				North Africa				Total
2017
Oil		—		Average sales price ($/bbl)		$	47.91			$	48.50			$	50.38			$	48.93
NGLs		—		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
NGLs		—		Average sales price ($/bbl)		$	14.72			$	—			$	15.01			$	14.82
Gas		—		Average sales price ($/mcf)		$	1.90			$	3.78			$	1.27			$	1.53
2015
Oil		—		Average sales price ($/bbl)		$	45.04			$	44.49			$	49.65			$	47.10
NGLs		—		Average sales price ($/bbl)		$	15.35			$	—			$	17.88			$	15.96
Gas		—		Average sales price ($/mcf)		$	2.15			$	5.20			$	0.91			$	1.49

(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, 2017, Occidental’s net productive and dry–exploratory and development wells completed.

						United			Latin			Middle East/
						States			America			North Africa			Total
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		—			—			—			—
2015
Oil		—		Exploratory		17			—			1			18
				Development		387			24			217			628
Gas		—		Exploratory		—			—			2			2
				Development		4			1			12			17
Dry		—		Exploratory		—			—			4			4
				Development		—			1			1			2

Productive Oil and Gas Wells

The following table sets forth, as of December 31, 2017, Occidental’s productive oil and gas wells (both producing and capable of production).

Wells at December 31, 2017 (a)						United States						Latin America					Middle East						Total
Oil		—		Gross (b)		16,464			(777	)		1,641			—		2,361			(1	)		20,466			(778	)
				Net (c)		14,265			(711	)		821			—		1,259			(1	)		16,345			(712	)
Gas		—		Gross (b)		2,622			(317	)		34			—		110			—			2,766			(317	)
				Net (c)		2,328			(298	)		31			—		57			—			2,416			(298	)

(a)	The numbers in parentheses indicate the number of wells with multiple completions.

(b)	The total number of wells in which interests are owned.

(c)	The sum of fractional interests.

(Unaudited)

Participation in Exploratory and Development Wells Being Drilled

The following table sets forth, as of December 31, 2017, Occidental’s participation in exploratory and development wells being drilled.

Wells at December 31, 2017						United States			Latin America			Middle East			Total
Exploratory and development wells
		—		Gross		38			3			24			65
		—		Net		33			2			15			50

At December 31, 2017, Occidental was participating in 87 pressure-maintenance projects, mostly waterfloods, in the United States, 1 in Latin America and 21 in the Middle East.

Oil and Gas Acreage

The following table sets forth, as of December 31, 2017, Occidental’s holdings of developed and undeveloped oil and gas acreage.

Thousands of acres at						United			Latin			Middle
December 31, 2017						States			America			East			Total
Developed (a)
		—		Gross (b)		5,990			130			631			6,751
		—		Net (c)		2,791			88			240			3,119
Undeveloped (d)
		—		Gross (b)		1,962			269			2,078			4,309
		—		Net (c)		625			213			1,241			2,079

(a)	Acres spaced or assigned to productive wells.

(b)	Total acres in which interests are held.

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

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

Occidental’s investment in developed and undeveloped acreage comprises numerous concessions, blocks and leases. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, Occidental may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, Occidental has generally been successful in obtaining extensions. Scheduled lease and concession expirations for undeveloped acreage over the next three years are not expected to have a material adverse impact on Occidental.

(Unaudited)

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

The following tables set forth the production and sales volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2017. 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)		2017			2016			2015
United States
Permian Resources		141			124			110
Permian EOR		150			145			145
South Texas and Other		13			33			73
Total		304			302			328
Latin America		32			34			37
Middle East/North Africa
Al Hosn Gas		71			64			35
Dolphin		42			43			41
Oman		95			96			89
Qatar		58			65			66
Other		—			26			72
Total		266			294			303
Total Production (MBOE) (a)		602			630			668
(See footnote following the Sales Volumes from Ongoing Operations table)

Production per Day from Ongoing Operations (MBOE)		2017			2016			2015
United States
Permian Resources		141			124			110
Permian EOR		150			145			145
Domestic and Other		5			4			6
Total		296			273			261
Latin America		32			34			37
Middle East
Al Hosn Gas		71			64			35
Dolphin		42			43			41
Oman		95			96			89
Qatar		58			65			66
Total		266			268			231
Total Production Ongoing Operations (MBOE) (a)		594			575			529
Sold domestic operations		8			29			67
Sold or Exited MENA operations		—			26			72
Total Production (MBOE) (a)		602			630			668
(See footnote following the Sales Volumes from Ongoing Operations table)

(Unaudited)

Production per Day by Products		2017			2016			2015
United States
Oil (MBBL)
Permian Resources		85			77			71
Permian EOR		113			108			110
South Texas and Other		2			4			21
Total		200			189			202
NGLs (MBBL)
Permian Resources		26			21			16
Permian EOR		27			27			29
South Texas and Other		2			5			10
Total		55			53			55
Natural gas (MMCF)
Permian Resources		184			158			137
Permian EOR		57			59			37
South Texas and Other		53			144			250
Total		294			361			424
Latin America
Oil (MBBL)		31			33			35
Natural gas (MMCF)		7			8			10
Middle East/North Africa
Oil (MBBL)
Al Hosn Gas		13			12			7
Dolphin		7			7			7
Oman		71			77			82
Qatar		59			65			66
Other		—			7			32
Total		150			168			194
NGLs (MBBL)
Al Hosn Gas		23			20			10
Dolphin		8			8			8
Total		31			28			18
Natural gas (MMCF)
Al Hosn Gas		211			190			109
Dolphin		159			166			158
Oman		138			115			44
Other		—			114			237
Total		508			585			548
Total Production (MBOE) (a)		602			630			668
(See footnote following the Sales Volumes from Ongoing Operations table)

(Unaudited)

Production per Day by Products from Ongoing Operations		2017			2016			2015
United States
Oil (MBBL)
Permian Resources		85			77			71
Permian EOR		113			108			110
Other Domestic		2			1			2
Total		200			186			183
NGLs (MBBL)
Permian Resources		26			21			16
Permian EOR		27			27			29
Total		53			48			45
Natural gas (MMCF)
Permian Resources		184			158			137
Permian EOR		57			59			37
Other Domestic		18			18			23
Total		259			235			197
Latin America
Oil (MBBL)		31			33			35
Natural gas (MMCF)		7			8			10
Middle East
Oil (MBBL)
Al Hosn Gas		13			12			7
Dolphin		7			7			7
Oman		71			77			82
Qatar		59			65			66
Total		150			161			162
NGLs (MBBL)
Al Hosn Gas		23			20			10
Dolphin		8			8			8
Total		31			28			18
Natural gas (MMCF)
Al Hosn Gas		211			190			109
Dolphin		159			166			158
Oman		138			115			44
Total		508			471			311
Total Production Ongoing Operations (MBOE) (a)		594			575			529
Sold domestic operations		8			29			67
Sold or Exited MENA operations		—			26			72
Total Production (MBOE) (a)		602			630			668
(See footnote following the Sales Volumes from Ongoing Operations table)

(Unaudited)

Sales Volumes per Day by Products		2017			2016			2015
United States								.
Oil (MBBL)		200			189			202
NGLs (MBBL)		55			53			55
Natural gas (MMCF)		294			361			424
Latin America
Oil (MBBL)		32			34			35
Natural gas (MMCF)		7			8			10
Middle East/North Africa
Oil (MBBL)
Al Hosn Gas		13			12			7
Dolphin		7			7			8
Oman		72			77			82
Qatar		58			66			67
Other		—			7			36
Total		150			169			200
NGLs (MBBL)
Al Hosn Gas		23			20			10
Dolphin		8			8			8
Total		31			28			18
Natural gas (MMCF)		508			585			548
Total Sales Volumes (MBOE) (a)		603			632			674
(See footnote following the Sales Volumes from Ongoing Operations table)

Sales Volumes per Day by Products from Ongoing Operations		2017			2016			2015
United States
Oil (MBBL)		200			186			183
NGLs (MBBL)		53			48			45
Natural gas (MMCF)		259			235			197
Latin America
Oil (MBBL)		32			34			35
Natural gas (MMCF)		7			8			10
Middle East
Oil (MBBL)
Al Hosn Gas		13			12			7
Dolphin		7			7			8
Oman		72			77			82
Qatar		58			66			67
Total		150			162			164
NGLs (MBBL)
Al Hosn Gas		23			20			10
Dolphin		8			8			8
Total		31			28			18
Natural gas (MMCF)		508			471			311
Total Sales Ongoing Operations (MBOE) (a)		595			577			531
Sold domestic operations		8			29			67
Sold or Exited MENA operations		—			26			76
Total Sales Volumes (MBOE) (a)		603			632			674

(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 2017, the average prices of WTI oil and NYMEX natural gas were $51.34 per barrel and $3.08, respectively, resulting in an oil to gas ratio of 17 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
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)
2015
Allowance for doubtful accounts		$	19			$	9			$	(3	)		$	(5	)		$	20		(b)
Environmental, litigation, tax and other reserves		$	672			$	119			$	2			$	(314	)		$	479		(c)

Note: The amounts presented represent continuing operations.

(a)	Primarily represents payments.

(b)	Of these amounts, $18 million, $17 million and $20 million in 2017, 2016 and 2015, respectively, are classified as current.

(c)	Of these amounts, $163 million, $197 million and $98 million in 2017, 2016 and 2015, respectively, are classified as current.