8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) January 30, 2014

OCCIDENTAL PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	1-9210	95-4035997
(State or other jurisdiction	(Commission	(I.R.S. Employer
of incorporation)	File Number)	Identification No.)

10889 Wilshire Boulevard
Los Angeles, California	90024
(Address of principal executive offices)	(ZIP code)

Registrant’s telephone number, including area code: (310) 208-8800

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions (see General Instruction A.2. below):

o  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 2 – Financial Information

Item 2.02.  Results of Operations and Financial Condition

On January 30, 2014, Occidental Petroleum Corporation released information regarding its results of operations for the three and twelve months ended December 31, 2013.  The exhibits to this Form 8-K and the information set forth in this Item 2.02 are being furnished pursuant to Item 2.02, Results of Operations and Financial Condition.  The full text of the press release is attached to this report as Exhibit 99.1.  The full text of the presentations of Stephen Chazen, Vicki Hollub and Cynthia Walker are attached to this report as Exhibit 99.2.  Investor Relations Supplemental Schedules are attached to this report as Exhibit 99.3.  Earnings Conference Call Slides are attached to this report as Exhibit 99.4.  Forward-Looking Statements Disclosure for Earnings Release Presentation Materials is attached to this report as Exhibit 99.5.  The information in this Item 2.02 and Exhibits 99.1 through 99.5, inclusive, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing.

Section 8 – Other Events

Item 8.01.  Other Events

On January 30, 2014, Occidental Petroleum Corporation announced core income for the fourth quarter of 2013 of $1.4 billion ($1.72 per diluted share), compared with $1.5 billion ($1.83 per diluted share) for the fourth quarter of 2012.  Net income was $1.6 billion ($2.04 per diluted share) for the fourth quarter of 2013, compared with $336 million ($0.42 per diluted share) for the fourth quarter of 2012.  The fourth quarter of 2013 includes an after-tax gain of $665 million ($0.83 per diluted share) from the sale of a portion of an investment in the General Partner of Plains All American Pipeline, L.P., and an after-tax charge of $395 million ($0.49 per diluted share) related to the impairment of certain non-producing domestic oil and gas acreage.  The fourth quarter of 2012 included an after-tax charge of $1.1 billion ($1.41 per diluted share), almost all of which was related to the impairment of gas assets in the Midcontinent.

Net income for the twelve months of 2013 was $5.9 billion ($7.32 per diluted share), compared with $4.6 billion ($5.67 per diluted share) for the same period in 2012.  After excluding the non-core items, 2013 core income was $5.6 billion ($6.95 per diluted share) for the full year of 2013, compared with $5.8 billion ($7.09 per diluted share) for the same period in 2012.

TWELVE-MONTH RESULTS

Oil and Gas

Oil and gas core earnings were $8.5 billion for the twelve months of 2013, compared with $8.8 billion for the same period of 2012.  The 2013 results reflect higher domestic earnings resulting from improved oil and gas realized prices and higher liquids volumes, lower operating costs partially offset by higher DD&A rates and lower NGL prices.  International results were lower on a year-over-year basis, due to lower liquids sales volumes, lower oil prices and higher operating costs and DD&A rates in the Middle East/North Africa.

Operating costs dropped significantly in 2013 compared with 2012. Domestic operating costs for the twelve months of 2013 were $14.43 per barrel, compared to $17.43 for the full year of 2012.  For the

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entire company, operating costs for the twelve months were $13.76 per barrel, compared to $14.99 for the full year of 2012.

Oil and gas production volumes for the twelve months were 763,000 barrels of oil equivalent per day (BOE) per day for 2013, compared with 766,000 BOE per day for the 2012 period.  Year-over-year, Oxy’s domestic production increased by 9,000 BOE per day.  International production was 12,000 BOE per day lower, mainly due to lower cost recovery barrels in the Dolphin and Oman operations and field and port strikes in Libya.  Daily sales volumes were 762,000 BOE in the twelve months of 2013, compared with 764,000 BOE for 2012.

Oxy's worldwide realized prices were flat for crude oil and lower for NGLs but increased for both domestic crude oil and natural gas on a year-over-year basis.  Worldwide realized crude oil prices were $99.84 per barrel for the twelve months of 2013, compared with $99.87 per barrel for the twelve months of 2012.  Worldwide NGL prices were $41.03 per barrel for the twelve months of 2013, a reduction of 9 percent from $45.18 per barrel for the twelve months of 2012.  Domestic crude oil prices increased from $93.72 per barrel in the twelve months of 2012 to $96.42 per barrel in the twelve months of 2013.  Domestic gas prices increased by about 29 percent from $2.62 per MCF in the twelve months of 2012 to $3.37 per MCF in the twelve months of 2013.

Chemical

Chemical core earnings were $612 million for the twelve months of 2013, compared with $720 million for the same period in 2012. The lower 2013 earnings primarily resulted from higher energy costs, higher ethylene costs and lower chlor-alkali and chlorinated organics pricing driven by continued unfavorable supply/demand fundamentals and reduced export demand.

Midstream, Marketing and Other

Midstream core earnings were $543 million for the twelve months of 2013, compared with $439 million for the same period in 2012. The 2013 results reflected higher earnings in the pipeline and power generation businesses and improved marketing and trading performance.  Marketing performance improved $110 million on a year-over-year basis mainly by capturing regional crude price differentials by utilizing new pipelines providing access to Gulf refineries.  These improvements were partially offset by lower income in the gas processing business due in part to the plant turnarounds in the Permian operations.

QUARTERLY RESULTS

Oil and Gas

Oil and gas segment earnings were $1.5 billion for the fourth quarter of 2013, which included $607 million pre-tax charges for impairment of certain non-producing domestic properties.  After excluding the asset impairments from both periods, oil and gas core earnings were $2.1 billion for the fourth quarter of 2013, compared with $2.3 billion for the fourth quarter of 2012.  The current quarter results reflect higher domestic earnings resulting from improved oil realized prices and higher volumes, and lower operating costs partially offset by higher DD&A rates.  International results were lower on a year-over-year basis, due to lower liquids sales volumes and higher DD&A rates in the Middle East/North Africa.

For the fourth quarter of 2013, daily oil and gas production volumes averaged 750,000 BOE, compared with 779,000 BOE in the fourth quarter of 2012.  While production increased in the California

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and South Texas operations, overall domestic production was lower due to severe weather conditions and plant turnarounds in the Permian operations and reduced domestic gas drilling.  Middle East/North Africa production was lower mostly due to lower cost recovery barrels in Oman and Iraq and field and port strikes in Libya.  Daily sales volumes were 772,000 BOE for the fourth quarter of 2013 and 784,000 BOE for the fourth quarter of 2012. Sales volumes were higher than production volumes due to the timing of liftings in Oxy’s international operations, primarily in Iraq.

Oxy’s realized price for worldwide crude oil increased 3 percent to $99.27 per barrel for the fourth quarter of 2013, compared with $96.19 per barrel for the fourth quarter of 2012.  Domestic crude oil prices increased by almost 8 percent in the fourth quarter of 2013 to $94.52 per barrel, compared to $87.81 per barrel in the fourth quarter of 2012.  Middle East/North Africa crude oil prices and worldwide NGL prices were lower on a year-over-year basis for the fourth quarter of 2013.  Domestic gas prices increased by almost 8 percent in the fourth quarter of 2013 to $3.33 per MCF, compared with $3.09 in the fourth quarter of 2012.

On a sequential quarterly basis, worldwide realized crude oil prices decreased approximately 5 percent and worldwide realized NGL prices increased approximately 10 percent.  On a geographic basis, domestic crude oil prices decreased by about 9 percent and Middle East/North Africa oil prices increased by about 3 percent.

Chemical

Chemical segment earnings for the fourth quarter of 2013 were $128 million, compared with $180 million in the fourth quarter of 2012.  The decrease was primarily due to higher energy and ethylene costs and lower caustic soda prices.  New chlor-alkali capacity resulted in a significant increase in competitive activity in the fourth quarter, causing price pressure.

Midstream, Marketing and Other

Midstream segment earnings were $1.1 billion for the fourth quarter of 2013.  After excluding non-core items, which were primarily the gain on the sale of a portion of the Plains Pipeline investment, core earnings were $68 million for the fourth quarter of 2013, compared with $75 million for the fourth quarter of 2012. The decrease reflected lower marketing and trading performance and weaker results in the gas processing business due in part to the plant turnarounds in the Permian operations, partially offset by higher earnings in the pipeline business.

Forward-Looking Statements

Portions of this press release contain forward-looking statements and involve risks and uncertainties that could materially affect expected results of operations, liquidity, cash flows and business prospects. Actual results may differ from anticipated results sometimes materially, and reported results should not be considered an indication of future performance. Factors that could cause results to differ include, but are not limited to: global commodity pricing fluctuations; supply and demand considerations for Occidental’s products; higher-than-expected costs; the regulatory approval environment; reorganization or restructuring of Occidental’s operations; not successfully completing, or any material delay of, field developments, expansion projects, capital expenditures, efficiency projects, acquisitions or dispositions; lower-than-expected production from development projects or acquisitions; exploration risks; general economic slowdowns domestically or internationally; political conditions and events; liability under environmental regulations including remedial actions; litigation; disruption or interruption of production or manufacturing or facility damage due to accidents, chemical releases, labor unrest, weather, natural disasters, cyber attacks or insurgent activity; failure of risk management; changes in law

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or regulations; or changes in tax rates. Words such as "estimate", "project", "predict", "will", "would", "should", "could", "may", "might", "anticipate", "plan", "intend", "believe", "expect", "aim", "goal", "target", "objective", "likely" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this release. Unless legally required, Occidental does not undertake any obligation to update any forward-looking statements, as a result of new information, future events or otherwise. Material risks that may affect Occidental’s results of operations and financial position appear in Part 1, Item 1A "Risk Factors" of the 2012 Form 10-K. Occidental posts or provides links to important information on its website at www.oxy.com.  Occidental calculates its reserves replacement ratio for a specified period by using the applicable oil-equivalent proved reserves additions divided by oil-equivalent production.

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Attachment 1
SUMMARY OF SEGMENT NET SALES AND EARNINGS
	Fourth Quarter						Twelve Months
($ millions, except per-share amounts)	2013			2012			2013			2012
SEGMENT NET SALES
Oil and Gas	$	4,953		$	4,874		$	19,132		$	18,906
Chemical		1,111			1,141			4,673			4,580
Midstream, Marketing and Other		374			355			1,538			1,399
Eliminations		(266	)		(199	)		(888	)		(713	)
Net Sales	$	6,172		$	6,171		$	24,455		$	24,172
SEGMENT EARNINGS
Oil and Gas (a)	$	1,511		$	522		$	7,894		$	7,095
Chemical (b)		128			180			743			720
Midstream, Marketing and Other (c)		1,098			75			1,573			439
		2,737			777			10,210			8,254
Unallocated Corporate Items
Interest expense, net		(23	)		(30	)		(110	)		(117	)
Income taxes		(973	)		(249	)		(3,755	)		(3,118	)
Other (d)		(93	)		(134	)		(423	)		(384	)
Income from Continuing Operations		1,648			364			5,922			4,635
Discontinued operations, net		(5	)		(28	)		(19	)		(37	)
NET INCOME	$	1,643		$	336		$	5,903		$	4,598
BASIC EARNINGS PER COMMON SHARE
Income from continuing operations	$	2.05		$	0.45		$	7.35		$	5.72
Discontinued operations, net		(0.01	)		(0.03	)		(0.02	)		(0.05	)
	$	2.04		$	0.42		$	7.33		$	5.67
DILUTED EARNINGS PER COMMON SHARE
Income from continuing operations	$	2.05		$	0.45		$	7.34		$	5.71
Discontinued operations, net		(0.01	)		(0.03	)		(0.02	)		(0.04	)
	$	2.04		$	0.42		$	7.32		$	5.67
AVERAGE COMMON SHARES OUTSTANDING
BASIC		801.7			807.1			804.1			809.3
DILUTED		802.1			807.7			804.6			810.0
(a) Oil and Gas - The fourth quarter and twelve months of 2013 include $607 million of pre-tax charges related
to the impairment of domestic non-producing acreage.   The fourth quarter and twelve months of 2012 include
$1.7 billion of pre-tax charges related to the impairment of domestic gas assets and related items.
(b) Chemical - Twelve months of 2013 includes a $131 million pre-tax gain for the sale of an investment in Carbocloro,
a Brazilian chemical operation.
(c) Midstream - The fourth quarter and twelve months of 2013 include a $1,030 million pre-tax gain for the sale of a
portion of an investment in Plains Pipeline and other items.
(d) Unallocated Corporate Items - Other - Twelve months of 2013 includes a $55 million pre-tax charge for the
estimated cost related to the employment and post-employment benefits for the Company's former Executive
Chairman and termination of certain other employees and consulting arrangements.

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Attachment 2
SUMMARY OF CAPITAL EXPENDITURES AND DD&A EXPENSE
	Fourth Quarter					Twelve Months
($ millions)	2013			2012		2013			2012
CAPITAL EXPENDITURES	$	2,486	(a)	$	2,510	$	9,037	(a)	$	10,226
DEPRECIATION, DEPLETION AND
AMORTIZATION OF ASSETS	$	1,451		$	1,191	$	5,347		$	4,511
(a) Includes 100 percent of the capital expenditures for BridgeTex Pipeline, which is being consolidated in Oxy's financial
statements.  Our partner contributes its share of the capital.  The Company's net capital expenditures after these
reimbursements were $8.8 billion and $2.4 billion for the twelve months and fourth quarter of 2013, respectively.

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Attachment 3
SIGNIFICANT TRANSACTIONS AND EVENTS AFFECTING EARNINGS
Occidental's results of operations often include the effects of significant transactions and events affecting earnings that vary widely and unpredictably in nature, timing and amount. Therefore, management uses a measure called "core results," which excludes those items. This non-GAAP measure is not meant to disassociate those items from management's performance, but rather is meant to provide useful information to investors interested in comparing Occidental's earnings performance between periods. Reported earnings are considered representative of management's performance over the long term. Core results is not considered to be an alternative to operating income reported in accordance with generally accepted accounting principles.
	Fourth Quarter
($ millions, except per-share amounts)	2013			Diluted EPS		2012			Diluted EPS
TOTAL REPORTED EARNINGS	$	1,643		$	2.04	$	336		$	0.42
Oil and Gas
Segment Earnings	$	1,511				$	522
Add:
Asset impairments and related items		607					1,731
Segment Core Results		2,118					2,253
Chemicals
Segment Earnings		128					180
Add:
No significant items affecting earnings		-					-
Segment Core Results		128					180
Midstream, Marketing and Other
Segment Earnings		1,098					75
Add:
Plains Pipeline sale gain and other		(1,030	)				-
Segment Core Results		68					75
Total Segment Core Results		2,314					2,508
Corporate
Corporate Results --
Non Segment (a)		(1,094	)				(441	)
Add:
Litigation reserves		-					20
Tax effect of pre-tax adjustments		154					(636	)
Discontinued operations, net (b)		5					28
Corporate Core Results - Non Segment		(935	)				(1,029	)
TOTAL CORE RESULTS	$	1,379		$	1.72	$	1,479		$	1.83
(a) Interest expense, income taxes, G&A expense and other.
(b) Amounts shown after tax.

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Attachment 4
SIGNIFICANT TRANSACTIONS AND EVENTS AFFECTING EARNINGS (continued)
	Twelve Months
($ millions, except per-share amounts)	2013			Diluted EPS		2012			Diluted EPS
TOTAL REPORTED EARNINGS	$	5,903		$	7.32	$	4,598		$	5.67
Oil and Gas
Segment Earnings	$	7,894				$	7,095
Add:
Asset impairments and related items		607					1,731
Segment Core Results		8,501					8,826
Chemicals
Segment Earnings		743					720
Add:
Carbocloro sale gain		(131	)				-
Segment Core Results		612					720
Midstream, Marketing and Other
Segment Earnings		1,573					439
Add:
Plains Pipeline sale gain and other		(1,030	)				-
Segment Core Results		543					439
Total Segment Core Results		9,656					9,985
Corporate
Corporate Results --
Non Segment (a)		(4,307	)				(3,656	)
Add:
Charge for former executives and
consultants (b)		55					-
Litigation reserves		-					20
Tax effect of pre-tax adjustments		179					(636	)
Discontinued operations, net (c)		19					37
Corporate Core Results - Non Segment		(4,054	)				(4,235	)
TOTAL CORE RESULTS	$	5,602		$	6.95	$	5,750		$	7.09
(a) Interest expense, income taxes, G&A expense and other.
(b) Reflects pre-tax charge for the estimated cost related to the employment and post-employment benefits for the
Company's former Executive Chairman and termination of certain other employees and consulting arrangements.
(c) Amounts shown after tax.

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Attachment 5
SUMMARY OF OPERATING STATISTICS - PRODUCTION
	Fourth Quarter		Twelve Months
	2013	2012	2013	2012
NET OIL, GAS AND LIQUIDS PRODUCTION PER DAY
United States
Oil (MBBL)
California	94	92	90	88
Permian	146	146	146	142
Midcontinent and Other	30	27	30	25
Total	270	265	266	255
NGLs (MBBL)
California	20	21	20	17
Permian	36	40	39	39
Midcontinent and Other	17	16	18	17
Total	73	77	77	73
Natural Gas (MMCF)
California	260	242	260	256
Permian	147	162	157	155
Midcontinent and Other	355	396	371	410
Total	762	800	788	821
Latin America
Oil  (MBBL) - Colombia	29	30	29	29
Natural Gas (MMCF) - Bolivia	12	12	12	13
Middle East / North Africa
Oil (MBBL)
Dolphin	7	7	6	8
Oman	64	74	66	67
Qatar	69	71	68	71
Other	29	40	39	40
Total	169	192	179	186
NGLs (MBBL)
Dolphin	7	7	7	8
Other	-	-	-	1
Total	7	7	7	9
Natural Gas (MMCF)
Dolphin	145	138	142	163
Oman	42	56	51	57
Other	253	242	241	232
Total	440	436	434	452
Barrels of Oil Equivalent (MBOE)	750	779	763	766

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Attachment 6
SUMMARY OF OPERATING STATISTICS - SALES
	Fourth Quarter		Twelve Months
	2013	2012	2013	2012
NET OIL, GAS AND LIQUIDS SALES PER DAY
United States
Oil (MBBL)	270	265	266	255
NGLs (MBBL)	73	77	77	73
Natural Gas (MMCF)	762	800	789	819
Latin America
Oil  (MBBL) - Colombia	23	30	27	28
Natural Gas (MMCF) - Bolivia	12	12	12	13
Middle East / North Africa
Oil (MBBL)
Dolphin	7	7	6	8
Oman	65	70	68	66
Qatar	66	75	67	71
Other	59	43	38	40
Total	197	195	179	185
NGLs (MBBL)
Dolphin	7	7	7	8
Other	-	2	-	1
Total	7	9	7	9
Natural Gas (MMCF)	440	436	434	452
Barrels of Oil Equivalent (MBOE)	772	784	762	764

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Section 9 - Financial Statements and Exhibits

Item 9.01.  Financial Statements and Exhibits

(d)	Exhibits
99.1	Press release dated January 30, 2014.
99.2	Full text of presentations of Stephen Chazen, Vicki Hollub and Cynthia Walker.
99.3	Investor Relations Supplemental Schedules.
99.4	Earnings Conference Call Slides.
99.5	Forward-Looking Statements Disclosure for Earnings Release Presentation Materials.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	OCCIDENTAL PETROLEUM CORPORATION
	(Registrant)
DATE:  January 30, 2014	/s/ ROY PINECI
	Roy Pineci, Vice President, Controller
	and Principal Accounting Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Press release dated January 30, 2014.
99.2	Full text of presentations of Stephen Chazen, Vicki Hollub and Cynthia Walker.
99.3	Investor Relations Supplemental Schedules.
99.4	Earnings Conference Call Slides.
99.5	Forward-Looking Statements Disclosure for Earnings Release Presentation Materials.

EX-99.1

EXHIBIT 99.1

For Immediate Release: January 30, 2014

Occidental Petroleum Announces 4th Quarter and Twelve Months of 2013 Net Income

● Q4 2013 core income of $1.4 billion, or $1.72 per diluted share

● Q4 2013 net income of $1.6 billion, or $2.04 per diluted share

● Q4 2013 total company oil and gas production of 750,000 barrels of oil equivalent per day

● Total year net income of $5.9 billion, or $7.32 per diluted share

HOUSTON --January 30, 2014 -- Occidental Petroleum Corporation (NYSE:OXY) announced core income for the fourth quarter of 2013 of $1.4 billion ($1.72 per diluted share), compared with $1.5 billion ($1.83 per diluted share) for the fourth quarter of 2012.  Net income was $1.6 billion ($2.04 per diluted share) for the fourth quarter of 2013, compared with $336 million ($0.42 per diluted share) for the fourth quarter of 2012.  The fourth quarter of 2013 includes an after-tax gain of $665 million ($0.83 per diluted share) from the sale of a portion of an investment in the General Partner of Plains All American Pipeline, L.P., and an after-tax charge of $395 million ($0.49 per diluted share) related to the impairment of certain non-producing domestic oil and gas acreage.  The fourth quarter of 2012 included an after-tax charge of $1.1 billion ($1.41 per diluted share), almost all of which was related to the impairment of gas assets in the Midcontinent.

Net income for the twelve months of 2013 was $5.9 billion ($7.32 per diluted share), compared with $4.6 billion ($5.67 per diluted share) for the same period in 2012.  After excluding the non-core items, 2013 core income was $5.6 billion ($6.95 per diluted share) for the full year of 2013, compared with $5.8 billion ($7.09 per diluted share) for the same period in 2012.

In announcing the results, Stephen I. Chazen, President and Chief Executive Officer, said, "We had strong results in our domestic program in 2013.  We grew our domestic liquids production by 15,000 barrels per day, or 5 percent, to 343,000 barrels per day on a year-over-year basis.  Our focused drilling program and emphasis on efficiencies yielded a 24-percent reduction in our drilling costs relative to 2012 and a 17-percent improvement in operating costs, resulting in domestic oil and gas operating expenses of $14.43 per BOE for the year.  Our domestic proved liquids reserve replacement was 228 percent and we replaced all of our domestic gas production with our drilling program.

"Based on our preliminary reserve estimates, we added about 470 million barrels of reserves, resulting in a reserve replacement ratio of 169 percent for the total company.  Of the

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total reserve additions, 156 percent, or about 433 million barrels, resulted from our development program.

"Our focus on capital and operating efficiencies helped us generate $12.9 billion of cash flow from operations during the twelve months of 2013.  We spent $8.8 billion of our cash flow on capital expenditures, repurchased almost 11 million shares and reduced our debt by 9 percent.  Our year-end cash balance was $3.4 billion compared to the 2012 year-end level of $1.6 billion."

TWELVE-MONTH RESULTS

Oil and Gas

Oil and gas core earnings were $8.5 billion for the twelve months of 2013, compared with $8.8 billion for the same period of 2012.  The 2013 results reflect higher domestic earnings resulting from improved oil and gas realized prices and higher liquids volumes, lower operating costs partially offset by higher DD&A rates and lower NGL prices.  International results were lower on a year-over-year basis, due to lower liquids sales volumes, lower oil prices and higher operating costs and DD&A rates in the Middle East/North Africa.

Operating costs dropped significantly in 2013 compared with 2012. Domestic operating costs for the twelve months of 2013 were $14.43 per barrel, compared to $17.43 for the full year of 2012.  For the entire company, operating costs for the twelve months were $13.76 per barrel, compared to $14.99 for the full year of 2012.

Oil and gas production volumes for the twelve months were 763,000 barrels of oil equivalent per day (BOE) per day for 2013, compared with 766,000 BOE per day for the 2012 period.  Year-over-year, Oxy’s domestic production increased by 9,000 BOE per day.  International production was 12,000 BOE per day lower, mainly due to lower cost recovery barrels in the Dolphin and Oman operations and field and port strikes in Libya.  Daily sales volumes were 762,000 BOE in the twelve months of 2013, compared with 764,000 BOE for 2012.

Oxy's worldwide realized prices were flat for crude oil and lower for NGLs but increased for both domestic crude oil and natural gas on a year-over-year basis.  Worldwide realized crude oil prices were $99.84 per barrel for the twelve months of 2013, compared with $99.87 per barrel for the twelve months of 2012.  Worldwide NGL prices were $41.03 per barrel for the twelve months of 2013, a reduction of 9 percent from $45.18 per barrel for the twelve months of 2012.  Domestic crude oil prices increased from $93.72 per barrel in the twelve months of 2012 to $96.42 per barrel in the twelve months of 2013.  Domestic gas prices increased by about 29percent from $2.62 per MCF in the twelve months of 2012 to $3.37 per MCF in the twelve months of 2013.

Chemical

Chemical core earnings were $612 million for the twelve months of 2013, compared with $720 million for the same period in 2012. The lower 2013 earnings primarily resulted from higher energy costs, higher ethylene costs and lower chlor-alkali and chlorinated organics

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pricing driven by continued unfavorable supply/demand fundamentals and reduced export demand.

Midstream, Marketing and Other

Midstream core earnings were $543 million for the twelve months of 2013, compared with $439 million for the same period in 2012. The 2013 results reflected higher earnings in the pipeline and power generation businesses and improved marketing and trading performance.  Marketing performance improved $110 million on a year-over-year basis mainly by capturing regional crude price differentials by utilizing new pipelines providing access to Gulf refineries.  These improvements were partially offset by lower income in the gas processing business due in part to the plant turnarounds in the Permian operations.

QUARTERLY RESULTS

Oil and Gas

Oil and gas segment earnings were $1.5 billion for the fourth quarter of 2013, which included $607 million pre-tax charges for impairment of certain non-producing domestic properties.  After excluding the asset impairments from both periods, oil and gas core earnings were $2.1 billion for the fourth quarter of 2013, compared with $2.3 billion for the fourth quarter of 2012.  The current quarter results reflect higher domestic earnings resulting from improved oil realized prices and higher volumes, and lower operating costs partially offset by higher DD&A rates.  International results were lower on a year-over-year basis, due to lower liquids sales volumes and higher DD&A rates in the Middle East/North Africa.

For the fourth quarter of 2013, daily oil and gas production volumes averaged 750,000 BOE, compared with 779,000 BOE in the fourth quarter of 2012.  While production increased in the California and South Texas operations, overall domestic production was lower due to severe weather conditions and plant turnarounds in the Permian operations and reduced domestic gas drilling.  Middle East/North Africa production was lower mostly due to lower cost recovery barrels in Oman and Iraq and field and port strikes in Libya.  Daily sales volumes were 772,000 BOE for the fourth quarter of 2013 and 784,000 BOE for the fourth quarter of 2012. Sales volumes were higher than production volumes due to the timing of liftings in Oxy’s international operations, primarily in Iraq.

Oxy’s realized price for worldwide crude oil increased 3 percent to $99.27 per barrel for the fourth quarter of 2013, compared with $96.19 per barrel for the fourth quarter of 2012.  Domestic crude oil prices increased by almost 8 percent in the fourth quarter of 2013 to $94.52 per barrel, compared to $87.81 per barrel in the fourth quarter of 2012.  Middle East/North Africa crude oil prices and worldwide NGL prices were lower on a year-over-year basis for the fourth quarter of 2013.  Domestic gas prices increased by almost 8 percent in the fourth quarter of 2013 to $3.33 per MCF, compared with $3.09 in the fourth quarter of 2012.

On a sequential quarterly basis, worldwide realized crude oil prices decreased approximately 5 percent and worldwide realized NGL prices increased approximately 10

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percent.  On a geographic basis, domestic crude oil prices decreased by about 9 percent and Middle East/North Africa oil prices increased by about 3 percent.

Chemical

Chemical segment earnings for the fourth quarter of 2013 were $128 million, compared with $180 million in the fourth quarter of 2012.  The decrease was primarily due to higher energy and ethylene costs and lower caustic soda prices.  New chlor-alkali capacity resulted in a significant increase in competitive activity in the fourth quarter, causing price pressure.

Midstream, Marketing and Other

Midstream segment earnings were $1.1 billion for the fourth quarter of 2013.  After excluding non-core items, which were primarily the gain on the sale of a portion of the Plains Pipeline investment, core earnings were $68 million for the fourth quarter of 2013, compared with $75 million for the fourth quarter of 2012. The decrease reflected lower marketing and trading performance and weaker results in the gas processing business due in part to the plant turnarounds in the Permian operations, partially offset by higher earnings in the pipeline business.

About Oxy

Occidental Petroleum Corporation (OXY) is an international oil and gas exploration and production company with operations in the United States, Middle East/North Africa and Latin America regions. Oxy is one of the largest U.S. oil and gas companies, based on equity market capitalization. Oxy's wholly owned subsidiary OxyChem manufactures and markets chlor-alkali products and vinyls. Oxy is committed to safeguarding the environment, protecting the safety and health of employees and neighboring communities and upholding high standards of social responsibility in all of the company's worldwide operations.

Forward-Looking Statements

Portions of this press release contain forward-looking statements and involve risks and uncertainties that could materially affect expected results of operations, liquidity, cash flows and business prospects. Actual results may differ from anticipated results sometimes materially, and reported results should not be considered an indication of future performance. Factors that could cause results to differ include, but are not limited to: global commodity pricing fluctuations; supply and demand considerations for Occidental’s products; higher-than-expected costs; the regulatory approval environment; reorganization or restructuring of Occidental’s operations; not successfully completing, or any material delay of, field developments, expansion projects, capital expenditures, efficiency projects, acquisitions or dispositions; lower-than-expected production from development projects or acquisitions; exploration risks; general economic slowdowns domestically or internationally; political conditions and events; liability under environmental regulations including remedial actions; litigation; disruption or interruption of production or manufacturing or facility damage due to accidents, chemical releases, labor unrest, weather, natural disasters, cyber attacks or insurgent activity; failure of risk

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management; changes in law or regulations; or changes in tax rates. Words such as "estimate", "project", "predict", "will", "would", "should", "could", "may", "might", "anticipate", "plan", "intend", "believe", "expect", "aim", "goal", "target", "objective", "likely" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this release. Unless legally required, Occidental does not undertake any obligation to update any forward-looking statements, as a result of new information, future events or otherwise. Material risks that may affect Occidental’s results of operations and financial position appear in Part 1, Item 1A "Risk Factors" of the 2012 Form 10-K. Occidental posts or provides links to important information on its website at www.oxy.com.  Occidental calculates its reserves replacement ratio for a specified period by using the applicable oil-equivalent proved reserves additions divided by oil-equivalent production.

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Contacts:

Melissa E. Schoeb (media)

melissa_schoeb@oxy.com

310-443-6504

or

Chris Stavros (investors)

chris_stavros@oxy.com

212-603-8184

For further analysis of Occidental's quarterly performance, please visit the

website: www.oxy.com

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Attachment 1
SUMMARY OF SEGMENT NET SALES AND EARNINGS
	Fourth Quarter						Twelve Months
($ millions, except per-share amounts)	2013			2012			2013			2012
SEGMENT NET SALES
Oil and Gas	$	4,953		$	4,874		$	19,132		$	18,906
Chemical		1,111			1,141			4,673			4,580
Midstream, Marketing and Other		374			355			1,538			1,399
Eliminations		(266	)		(199	)		(888	)		(713	)
Net Sales	$	6,172		$	6,171		$	24,455		$	24,172
SEGMENT EARNINGS
Oil and Gas (a)	$	1,511		$	522		$	7,894		$	7,095
Chemical (b)		128			180			743			720
Midstream, Marketing and Other (c)		1,098			75			1,573			439
		2,737			777			10,210			8,254
Unallocated Corporate Items
Interest expense, net		(23	)		(30	)		(110	)		(117	)
Income taxes		(973	)		(249	)		(3,755	)		(3,118	)
Other (d)		(93	)		(134	)		(423	)		(384	)
Income from Continuing Operations		1,648			364			5,922			4,635
Discontinued operations, net		(5	)		(28	)		(19	)		(37	)
NET INCOME	$	1,643		$	336		$	5,903		$	4,598
BASIC EARNINGS PER COMMON SHARE
Income from continuing operations	$	2.05		$	0.45		$	7.35		$	5.72
Discontinued operations, net		(0.01	)		(0.03	)		(0.02	)		(0.05	)
	$	2.04		$	0.42		$	7.33		$	5.67
DILUTED EARNINGS PER COMMON SHARE
Income from continuing operations	$	2.05		$	0.45		$	7.34		$	5.71
Discontinued operations, net		(0.01	)		(0.03	)		(0.02	)		(0.04	)
	$	2.04		$	0.42		$	7.32		$	5.67
AVERAGE COMMON SHARES OUTSTANDING
BASIC		801.7			807.1			804.1			809.3
DILUTED		802.1			807.7			804.6			810.0
(a) Oil and Gas - The fourth quarter and twelve months of 2013 include $607 million of pre-tax charges related
to the impairment of domestic non-producing acreage.   The fourth quarter and twelve months of 2012 include
$1.7 billion of pre-tax charges related to the impairment of domestic gas assets and related items.
(b) Chemical - Twelve months of 2013 includes a $131 million pre-tax gain for the sale of an investment in Carbocloro,
a Brazilian chemical operation.
(c) Midstream - The fourth quarter and twelve months of 2013 include a $1,030 million pre-tax gain for the sale of a
portion of an investment in Plains Pipeline and other items.
(d) Unallocated Corporate Items - Other - Twelve months of 2013 includes a $55 million pre-tax charge for the
estimated cost related to the employment and post-employment benefits for the Company's former Executive
Chairman and termination of certain other employees and consulting arrangements.

Attachment 2
SUMMARY OF CAPITAL EXPENDITURES AND DD&A EXPENSE
	Fourth Quarter					Twelve Months
($ millions)	2013			2012		2013			2012
CAPITAL EXPENDITURES	$	2,486	(a)	$	2,510	$	9,037	(a)	$	10,226
DEPRECIATION, DEPLETION AND
AMORTIZATION OF ASSETS	$	1,451		$	1,191	$	5,347		$	4,511
(a) Includes 100 percent of the capital expenditures for BridgeTex Pipeline, which is being consolidated in Oxy's financial
statements.  Our partner contributes its share of the capital.  The Company's net capital expenditures after these
reimbursements were $8.8 billion and $2.4 billion for the twelve months and fourth quarter of 2013, respectively.

Attachment 3
SIGNIFICANT TRANSACTIONS AND EVENTS AFFECTING EARNINGS
Occidental's results of operations often include the effects of significant transactions and events affecting earnings that vary widely and unpredictably in nature, timing and amount. Therefore, management uses a measure called "core results," which excludes those items. This non-GAAP measure is not meant to disassociate those items from management's performance, but rather is meant to provide useful information to investors interested in comparing Occidental's earnings performance between periods. Reported earnings are considered representative of management's performance over the long term. Core results is not considered to be an alternative to operating income reported in accordance with generally accepted accounting principles.
	Fourth Quarter
($ millions, except per-share amounts)	2013			Diluted EPS		2012			Diluted EPS
TOTAL REPORTED EARNINGS	$	1,643		$	2.04	$	336		$	0.42
Oil and Gas
Segment Earnings	$	1,511				$	522
Add:
Asset impairments and related items		607					1,731
Segment Core Results		2,118					2,253
Chemicals
Segment Earnings		128					180
Add:
No significant items affecting earnings		-					-
Segment Core Results		128					180
Midstream, Marketing and Other
Segment Earnings		1,098					75
Add:
Plains Pipeline sale gain and other		(1,030	)				-
Segment Core Results		68					75
Total Segment Core Results		2,314					2,508
Corporate
Corporate Results --
Non Segment (a)		(1,094	)				(441	)
Add:
Litigation reserves		-					20
Tax effect of pre-tax adjustments		154					(636	)
Discontinued operations, net (b)		5					28
Corporate Core Results - Non Segment		(935	)				(1,029	)
TOTAL CORE RESULTS	$	1,379		$	1.72	$	1,479		$	1.83
(a) Interest expense, income taxes, G&A expense and other.
(b) Amounts shown after tax.

Attachment 4
SIGNIFICANT TRANSACTIONS AND EVENTS AFFECTING EARNINGS (continued)
	Twelve Months
($ millions, except per-share amounts)	2013			Diluted EPS		2012			Diluted EPS
TOTAL REPORTED EARNINGS	$	5,903		$	7.32	$	4,598		$	5.67
Oil and Gas
Segment Earnings	$	7,894				$	7,095
Add:
Asset impairments and related items		607					1,731
Segment Core Results		8,501					8,826
Chemicals
Segment Earnings		743					720
Add:
Carbocloro sale gain		(131	)				-
Segment Core Results		612					720
Midstream, Marketing and Other
Segment Earnings		1,573					439
Add:
Plains Pipeline sale gain and other		(1,030	)				-
Segment Core Results		543					439
Total Segment Core Results		9,656					9,985
Corporate
Corporate Results --
Non Segment (a)		(4,307	)				(3,656	)
Add:
Charge for former executives and
consultants (b)		55					-
Litigation reserves		-					20
Tax effect of pre-tax adjustments		179					(636	)
Discontinued operations, net (c)		19					37
Corporate Core Results - Non Segment		(4,054	)				(4,235	)
TOTAL CORE RESULTS	$	5,602		$	6.95	$	5,750		$	7.09
(a) Interest expense, income taxes, G&A expense and other.
(b) Reflects pre-tax charge for the estimated cost related to the employment and post-employment benefits for the
Company's former Executive Chairman and termination of certain other employees and consulting arrangements.
(c) Amounts shown after tax.

Attachment 5
SUMMARY OF OPERATING STATISTICS - PRODUCTION
	Fourth Quarter		Twelve Months
	2013	2012	2013	2012
NET OIL, GAS AND LIQUIDS PRODUCTION PER DAY
United States
Oil (MBBL)
California	94	92	90	88
Permian	146	146	146	142
Midcontinent and Other	30	27	30	25
Total	270	265	266	255
NGLs (MBBL)
California	20	21	20	17
Permian	36	40	39	39
Midcontinent and Other	17	16	18	17
Total	73	77	77	73
Natural Gas (MMCF)
California	260	242	260	256
Permian	147	162	157	155
Midcontinent and Other	355	396	371	410
Total	762	800	788	821
Latin America
Oil  (MBBL) - Colombia	29	30	29	29
Natural Gas (MMCF) - Bolivia	12	12	12	13
Middle East / North Africa
Oil (MBBL)
Dolphin	7	7	6	8
Oman	64	74	66	67
Qatar	69	71	68	71
Other	29	40	39	40
Total	169	192	179	186
NGLs (MBBL)
Dolphin	7	7	7	8
Other	-	-	-	1
Total	7	7	7	9
Natural Gas (MMCF)
Dolphin	145	138	142	163
Oman	42	56	51	57
Other	253	242	241	232
Total	440	436	434	452
Barrels of Oil Equivalent (MBOE)	750	779	763	766

Attachment 6
SUMMARY OF OPERATING STATISTICS - SALES
	Fourth Quarter		Twelve Months
	2013	2012	2013	2012
NET OIL, GAS AND LIQUIDS SALES PER DAY
United States
Oil (MBBL)	270	265	266	255
NGLs (MBBL)	73	77	77	73
Natural Gas (MMCF)	762	800	789	819
Latin America
Oil  (MBBL) - Colombia	23	30	27	28
Natural Gas (MMCF) - Bolivia	12	12	12	13
Middle East / North Africa
Oil (MBBL)
Dolphin	7	7	6	8
Oman	65	70	68	66
Qatar	66	75	67	71
Other	59	43	38	40
Total	197	195	179	185
NGLs (MBBL)
Dolphin	7	7	7	8
Other	-	2	-	1
Total	7	9	7	9
Natural Gas (MMCF)	440	436	434	452
Barrels of Oil Equivalent (MBOE)	772	784	762	764

EX-99.2

EXHIBIT 99.2

Occidental Petroleum Corporation

STEPHEN CHAZEN

President and Chief Executive Officer

– Conference Call –

Fourth Quarter 2013 Earnings

January 30, 2014

Houston, Texas

Thank you, Chris.

We just finished a very successful year meeting or exceeding the goals we set out for ourselves and are looking to continue our strong performance in 2014.  Let me give you a brief overview of key 2013 highlights:

— We grew our domestic oil production by 11,000 barrels per day over 2012 to 266,000 per day;

— We exceeded our capital efficiency goals, reducing our drilling costs by 24 percent from the 2012 level;

— We reduced domestic operating costs by 17 percent;

— We added about 470 million barrels of reserves achieving an overall replacement ratio of 169 percent;

— Our total costs incurred associated with those reserve adds were about $7.7 billion, resulting in an apparent finding and development cost of under $17;

— We increased our return on capital employed from 10.3 percent in 2012 to 12.2 percent in 2013.

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Turning now to some of the specifics of the key accomplishments in 2013.

As a result of our development program, we improved our capital efficiency by 24 percent domestically over 2012, which translates to about a $900 million reduction in capital for the wells drilled in 2013.  Of this improvement, 50 percent came from the Permian Basin, 25 percent from California and 25 percent from the rest of the domestic assets.  We accomplished these improvements while successfully completing our program by drilling approximately what we had planned.  We also reduced our domestic operating costs by 17 percent, or by about $470 million compared to 2012.  About 48 percent of this improvement was in the Permian Basin, 46 percent was in California and the remainder was in the other domestic assets.  While we focused on these efficiencies, we also grew our domestic oil production by 11,000 barrels per day.

With respect to reserves, we had a very successful year in growing the Company’s reserve base by adding substantially more reserves than we produced, over 90 percent of which was added through our organic development program.  We ended the year, based on a preliminary estimate, with about 3.5 billion barrels of reserves, which represents an all-time high for the company.

Our total company reserve replacement ratio from all categories, before dispositions, was about 169 percent, or about 470 million barrels of new reserves, compared with 278 million barrels we produced during the year.  In the United States, our reserve replacement ratio was 190 percent.  The replacement ratios of the California properties and the Permian non-CO2 properties were similar to the overall company ratio.  Our reserves replacement ratio for liquids from all categories was 195 percent for the total

2

company and 228 percent domestically.  This reflects our emphasis on oil drilling instead of gas.  Our total costs incurred related to the total reserve additions for the year, on a preliminary basis, were approximately $7.7 billion.

Over the past several years, we have built a large portfolio of growth oriented assets in the U.S.  In 2013, we spent a much larger portion of our investment dollars on the development of this portfolio.  Our organic reserve replacement for the year reflects the positive results of the development efforts capitalizing on the large portfolio built over the years.  Our 2013 development program, excluding acquisitions, replaced about 168 percent of our domestic production with about 291 million barrels of reserve adds.  In addition, we transferred 115 million barrels of proved undeveloped reserves to the proved developed category domestically as a result of the 2013 development program.  Our 2013 acquisitions were at a multi-year low of $550 million providing reserve adds of 32 million barrels.

At year end, we estimate that 73 percent of our total proved reserves were liquids, increasing from 72 percent in 2012.  Of the total reserves, about 70 percent were proved developed reserves, compared to 73 percent in 2012.  The increase in the share of the proved undeveloped reserves compared to last year was the result of the reserves added for the Al Hosn Gas Project.  We expect to move these reserves to the proved developed category at the end of this year once initial production starts in the fourth quarter.

Through the success of our drilling program and capital efficiency initiatives, we lowered our finding and development costs over recent years.  As a result, we expect our depreciation, depletion and amortization expense to be around $17.40 per barrel in 2014, only a small increase from $17.10 in

3

2013.  This is consistent with our expectations that the DD&A rate of growth should flatten out as recent investments come online and finding and development costs come down.  The success of our organic reserve additions and the efficiencies we have achieved in our operations demonstrates the significant progress we have made in turning the Company into a competitive domestic producer.  One of our long-term goals domestically has been to achieve a 50 percent pretax margin after finding and development and cash operating costs to generate solid returns.  We believe we are achieving that now and expect to continue to do so going forward.

Consistent with what we have said repeatedly, our focus in 2013 was to enhance shareholder value through our results.  For this purpose, our program was heavily focused on growing our domestic oil production, improving our capital efficiency and our finding and development costs and lowering our operating costs.  We met or exceeded all of these goals and as a result, we increased our return on capital employed to 12.2 percent, a significant improvement from the 10.3 percent level in 2012 and a testament to the hard work and dedication of all of our employees.  We expect to see further improvements in our returns in coming years as a result of recent investments.

Turning to this year, our 2014 program is designed to improve upon last year’s strong performance.  Let me highlight the key elements of the 2014 program, which I will discuss without reflecting any of the effects of our strategic review initiatives.

We expect our total 2014 capital program to be about $10.2 billion compared to the $8.8 billion we spent in 2013.  The increase includes about $400 million of additional capital allocated to each of our California and Permian operations largely for additional drilling to accelerate their

4

development plans and production growth.  An additional $0.1 billion will be spent in these and other domestic assets for facilities projects that were deferred from 2013.  The domestic oil and gas capital program will continue to focus on growing oil production and the entire increase in capital will go to oil projects in California and the Permian business units.  We also expect to continue to fund growth opportunities in our key international assets, mainly in Oman and Qatar, and complete the Al Hosn Gas Project.  Our 2014 capital for Oman and Qatar will increase by about $0.3 billion over 2013.  Our exploration capital will increase by about $0.1 billion, in part due to deferred spending from 2013.  Our midstream capital will increase by about $0.1 billion as a result of spending on the BridgeTex pipeline and two new terminals at Ingleside and our chemical capital will increase $0.1 billion due to the Mexichem joint venture we announced last year, while we complete the New Johnsonville chlor-alkali facility.  Our success in improving our capital efficiency and operating cost structure has provided us with the ability to expand our development opportunities that meet our financial return targets.  The capital program and production growth that I outlined reflects the benefit of our streamlined structure and our commitment to continue to fuel growth by exploiting our large portfolio primarily in California and the Permian basin.

With respect to our 2014 production, we expect our companywide production volumes to grow to between 780,000 and 790,000 barrels per day compared to 763,000 barrels per day in 2013, with a fourth quarter exit rate of over 800,000 barrels per day, excluding the planned Al Hosn production.  This increase will come almost entirely from domestic oil production while we expect to see a continued modest drop in our domestic gas volumes.  Our domestic oil production is expected to grow from 266,000 barrels per day in

5

2013 to between 280,000 and 295,000 barrels per day in 2014, or about 9 percent.  This growth will come fairly evenly from our California and Permian operations.  Internationally, excluding Al Hosn we expect production to grow slightly.

While the elements of the 2014 program that I discussed assumes no changes to the Company structure or its mix of assets, we do expect the Company to look significantly different by the end of the year.  The strategic review we are undertaking will result in significant changes to the Company’s asset mix.  Our capital program, production expectations and other elements of the 2014 program will be adjusted as related transactions are concluded.

Finally, some of the longer lead time investments we have been making over the past couple of years will start contributing to our results this year.  Specifically:

— The Al Hosn Gas Project is expected to start its initial production in the fourth quarter and start contributing to our cash flow;

— We expect the BridgeTex pipeline to come online around the third quarter and start contributing to our Midstream earnings and cash flow;

— The New Johnsonville chlor-alkali plant is expected to come online early in the year and will make a positive contribution to the operations of our chemical business.

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With respect to the initiatives outlined in the first phase of the Company’s strategic review announced last year, we completed the sale of a portion of the Company’s investment in the General Partner of Plains All American Pipeline in October, resulting in pre-tax proceeds of about $1.4 billion.  After this sale, we continue to hold about a 25 percent interest in the Plains General Partner, which at current market prices would be valued at about $4 billion.

We have made steady progress on our discussions with key partners in the countries where we operate in the MENA region for the sale of a minority interest in our operations there.  Due to the scale and the complexities of a potential transaction, we expect these discussions to continue through the first half of this year.  We have also made good progress in our pursuit of strategic alternatives for select Midcontinent assets.  We expect to provide further information on any transactions as they conclude around the end of the second quarter and will announce material developments as they occur.

In the fourth quarter, we used the Plains proceeds to retire $625 million of debt, reducing our debt load by about 9 percent, and to purchase almost 10 million shares of the Company’s stock with a cash outlay of $880 million.  We ended the year with a debt-to-capitalization ratio of 14 percent.

At the Board’s February meeting we will review the Company’s dividend policy, status of the strategic alternatives and share repurchase authority.

7

Many of the steps we have taken in 2013, including our success in improving our efficiency and the actions that our Board has authorized, lay the groundwork for stronger results for this year and beyond.  The operational improvements we expect to achieve in 2014, coupled with the strategic actions we expect to execute this year, should place the Company in a position to improve its returns while continuing to grow and increase its dividends to maximize shareholder value.

Vicki Hollub will now provide a more detailed discussion of our California and Permian operations.

Throughout this presentation, barrels may refer to barrels of oil, barrels of liquids or barrels of oil equivalents or BOE, which include natural gas, as the context requires.

8

Occidental Petroleum Corporation

Vicki Hollub

Executive Vice President – U.S. Operations

– Conference Call –

Fourth Quarter 2013 Earnings Announcement

January 30, 2014

Houston, Texas

Thank you, Steve.

This morning I will review two of our largest domestic operations, our Permian and California businesses, describing our 2014 plans as well as longer-term growth opportunities.  In 2013 we implemented an important transition plan in both of these businesses, and the success we achieved built a solid foundation for long-term growth.

In 2014, the specific goals for our operations are:

— Continue the development of our large anchor projects in each of our operating areas, which will enable us to allocate a significant portion of our capital to projects with solid returns, low execution risk and long term growth.

— Further reduce our drilling and completion costs to improve our finding and development costs and our project economics.

9

— Continue to optimize operating costs without affecting production to improve our current earnings and free cash flow.

— Build on our successful exploration efforts in each of our core areas.

— Evaluate data and test various new concepts in our pilot areas, which will set up the anchor projects of the future.

Permian Basin

We manage our Permian Basin operations through two business units, the Permian EOR business, which combines CO2 and waterfloods, and the Permian Resources business, which is where our growth oriented unconventional opportunities are managed.  I will refer to the CO2 and waterflood business as Permian EOR and the other business as Permian Resources.  The Permian Basin designation will be for the combined operations.  In the Permian Basin we spent over $1.7 billion of capital in 2013 with 64% focused on our Permian Resources assets.  In 2014, we plan to spend just under $2.2 billion overall in the Basin. The entire $450 million increase will be spent on our Permian Resources assets, representing approximately 70% of our total capital spend in the Basin.  We expect the Permian EOR business to offset its decline in 2014 and actually grow 1.4%.  The Permian Resources oil production is expected to grow faster in a range of 20% to 25% and its total production by 13% to 16%.  On a combined basis for the Permian Basin, this should translate to oil production growth of over 6% in 2014 and total overall production growth of over 5% while generating $1.8 billion of cash flow after capital.

2013 was a pivotal year for our Permian Basin operations.  First, we improved our capital efficiency by 25% and reduced our operating expenses by $3.22 per barrel, or 17%.  We also began transitioning to a horizontal

10

drilling program.  We drilled 49 horizontal wells with 47 completed and producing.  The combination of improvements in well costs, our own results and those of neighboring operators have given us the confidence to dramatically shift our program to more horizontal drilling in 2014.  Our Permian Resources team will average running about 21 rigs  of which 17 will be drilling horizontal wells.  We plan to drill approximately 345 total wells, about 50% of which will be horizontal.  This compares to 330 total wells drilled in 2013 where only 15% were horizontal.

We have two main goals for our Permian Resources business in 2014.  First, we intend to continue the evaluation of the potential across our full acreage position.  Second, we plan to pilot various development strategies, including optimal lateral length, frac design and well spacing both laterally and vertically.  We believe this will position us for accelerated development as we exit 2014 and go into 2015.

We believe we have one of the most promising and underexploited unconventional portfolios in the Basin.  In 2013, we added 200 thousand net prospective acres to our unconventional portfolios, and now have about 1.9 million prospective acres.  This is a prime position in the Permian Basin.  Our acreage in the Midland Basin, Texas Delaware Basin and New Mexico give us exposure to all unconventional plays, which is unique. This will give us flexibility to develop our most attractive opportunities first, and to mitigate risks.  Based on the work we have done to date, we have identified approximately 4,500 drilling locations across our portfolio, representing 1.2 billion net barrels of resource potential.  We believe we have made conservative assumptions regarding prospective acres, well spacing and expected ultimate recoveries and expect these numbers will grow as we learn more.  We see the largest near-term growth in the Midland Basin, which

11

represents about two-thirds of our currently assessed resource potential.  However, our Delaware Basin prospective acreage is significantly larger, and the potential there should continue to grow.

We believe our measured approach to our unconventional portfolio has worked to our advantage.  Our Permian Resources production comes from approximately 9,500 gross wells, of which 54% are operated by other producers.  On a net basis, we have approximately 4,400 wells of which only 15% are non-operated.  This has given us the opportunity to observe the results achieved by other operators in the Basin, learn from those results and optimize our approach to maximize the opportunities on our acreage.   The success of our capital and operating cost efficiency efforts in 2013, has also enabled us to significantly improve  our cost structure  which has increased our opportunity set.  For example, a typical well in the Collie area that had IRR of 24% before our capital and operating cost reductions, now yields IRR of 48% using the same product prices.  We achieved similar success in all of our most active areas across the business unit.  Finally we have established a multi-step methodical process for our unconventional acreage in the Permian Resources business that includes (i) exploration to establish the presence of a commercial resource; (ii) testing and data gathering to optimize well and completion design; (iii) pilot programs to assess variability of well performance to design full field development plans; and (iv) transition to manufacturing mode for full field development.  This process is helping us to prudently develop our acreage, maximizing cash flow and returns. As a result, we are now prepared to accelerate our activities in our Permian Resources business where we believe the opportunity in front of us is one of the biggest in the Basin.

12

Now, I will review our program in more detail beginning with the Midland Basin.

We have been most active with our horizontal activity to date in the Midland Basin where we have drilled 16 wells.  In 2014, we plan to spend approximately $790 million to drill 147 wells including 74 horizontal wells.  We expect to average 8 rigs in this area during the year.  Our largest opportunity here is in the Wolfcamp Shale where we have tested Wolfcamp A and B benches and plan to target our activity to test the remaining benches.

One of our most successful pilot projects in this basin is South Curtis Ranch, which has now gone into full field development mode.  This is a property that we acquired in 2010. We have drilled 63 vertical and 6 horizontal wells to date and plan to drill over 200 additional horizontal wells on this acreage.  Results thus far have been as expected with initial thirty-day production rates for the horizontal wells averaging approximately 800 boepd.

In the Midland Basin, we also believe there is substantial potential in the Cline, which is currently under evaluation. We have drilled 6 horizontal Cline wells so far and plan to drill another 5 to 10 in 2014.  Preliminary results indicate we may have the opportunity to drill up to 450 Cline wells in the Midland Basin.

Another pilot project is horizontal drilling in the Spraberry where we plan to drill our first horizontal well in the first quarter and will evaluate next steps with the results.  In addition to the horizontal activity, we also plan to continue our legacy vertical Wolfberry development.

In the Texas Delaware Basin, we plan to spend approximately $370 million in 2014 to drill 91 wells including 48 horizontal wells.  We expect to

13

average 5 rigs during the year.  Our horizontal activity will be focused in the Wolfcamp where we believe the A, B and C benches will prove to be the most prospective.  We drilled or participated in 3 horizontal Wolfcamp wells in 2013 and will increase that to 45 in 2014.  Our activity is centered in Reeves County where we historically have drilled vertical Wolfbone wells.  Early horizontal results are proving to have better economics, but there are some plays where vertical development is still more efficient.  In our Collie area, we plan to drill 43 vertical wells targeting the Bell and Cherry Canyon formations.  This represents a continuation of the one rig program we executed in 2013.

In New Mexico, we plan to spend approximately $370 million to drill 97 wells including 50 horizontal wells.  We expect to average 4 rigs during the year.  The Bone Spring formation in New Mexico is the second largest opportunity in our portfolio behind the Wolfcamp Shale.  In 2013, we drilled 16 horizontal wells testing the 1st, 2nd and 3rd Bone Spring sand intervals.  Our results were very encouraging, and we expect to increase the program to drill 30 horizontal Bone Spring sand wells in 2014.

Of the $2.2 billion to be spent in the Permian Basin in 2014, $660 million will be allocated to our Permian EOR business.  As I previously mentioned, this business unit is a combination of CO2 and water floods.  It is symbiotic to manage these assets together as they have similar development characteristics and ongoing monitoring and maintenance requirements.  The last couple of years we have actually spent more capital on waterfloods as we mature the next CO2 developments.  In 2014, 25% of the $660 million will be spent on current waterflood development and the remainder on CO2 floods.  Further, we have 1.4 billion net barrels oil equivalent in reserves and potential resources remaining to be developed in the Permian EOR

14

business.  We believe we are the efficiency leader in the Basin in applying CO2 flood technology to develop this potential and we have the ability to accelerate growth in our EOR projects as more CO2 becomes available.  As a result of our efficiency advantage, many projects that don’t work for others, work for us.

Permian Exploration

Over the last several years the focus of our Permian exploration program has been to identify unconventional opportunities, which are then transitioned to full field development through the evaluation process I explained earlier.  Our approach has been very successful giving us a large opportunity set that we are now working to fully develop.  We continue to see the addition of new plays in the Basin and see years of exploration drilling opportunities ahead in our 2 million prospective acre position.

Business Strategy

Now that I have gone through some of the specifics of our program for the Permian Basin, I will explain our overall business strategy.  We are approaching our development program with a multi pronged strategy that (i) maximizes the field resource potential; (ii) controls costs to optimize returns; and (iii) gives us a strategic advantage to improve our realizations.  We are using targeted horizontal and vertical drilling as appropriate, optimizing development and completion plans from lateral length to frac efficiency as well as lift strategies to maximize recovery. We are making heavier infrastructure investments like power, water handling and gas processing to pre-plan for life of field success.  These strategies, coupled with our successful exploration program, accomplish the first of these objectives.  We

15

will continue to manage costs and take advantage of our progress along the learning curve with leading technologies and execution efficiencies, to accomplish the second.  We are also investing in additional take-away capacity, including the completion of the BridgeTex pipeline and build out of our gathering systems, which will give our crude a strategic advantage to reach either the Houston Ship Channel or Corpus Christi markets.

Finally, I would like to comment on our plans for the Permian Basin over the next several years.  With the combined businesses, we have more than 2.5 billion barrels of oil equivalent in reserves and potential resources.  Within each business unit we have the flexibility to shift capital among projects within that business, as well as the flexibility to shift capital between the two businesses as needed.  Our large and diverse portfolio creates opportunities for a variety of growth options.  In the Permian Resources business, at our current pace, we believe we have over 15 years of development and growth opportunities.  Given that the Permian EOR business is generating significant cash flow and we expect our opportunity set to continue to grow, we plan to double our rigs over the next three years to accelerate the development of the Permian Resources unit’s growth opportunities.  We expect this to result in the doubling of our Resources unit’s production from approximately 64 mboepd in 2013 to more than 120 mboepd in 2016.  In Permian EOR while it is large with a somewhat slower growth curve, we have significant opportunities going forward with continued positive cash flow to fuel the growth of the Resources unit.  Combined with the EOR growth opportunities, we expect to grow our overall Permian Basin production by roughly a 10% compounded annual growth rate through 2016.

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California

Now I will shift to California.  In 2013, we spent $1.5 billion of capital.  Our main goals were to deliver a predictable outcome, advance low-risk projects that contribute to long-term growth, reduce the cost structure, lower our base decline, create a more balanced portfolio and test exploration and development concepts.  We achieved every one of these objectives.  We produced 154 mboepd and generated $1.3 billion of free cash flow after capital.  We progressed the development of our steam floods in Kern Front and Lost Hills, and started the redevelopment of our Huntington Beach Field.  We improved our capital efficiency by 20% versus 2012 and also reduced operating costs by $4.70 per BOE, or 20%.

Overall in 2014, we intend to continue the capital strategy shift initiated last year, which was to focus the majority of our capital on low decline projects.  Our goals for this year are to accelerate the rate of production growth and maintain our lower cost structure. We will also continue to advance several low-risk, high-return long-term growth projects and capitalize on our exploration successes.  In 2014, we plan to spend $1.9 billion of capital, of which approximately 40% will be spent on water floods, 20% on steam floods and 40% on unconventional and other developing plays.

We expect to average about 27 rigs in California in 2014, compared to an average of 20 rigs in 2013.  We plan to drill around 1,050 wells in 2014 compared to 770 in 2013.  We expect this program to deliver around 11% oil production growth, or over 4% total production growth, while generating $1.0 billion of free cash flow after capital at current prices.   We believe the rate of growth will further accelerate in 2015 and beyond as a number of the steam and water flood projects reach full production and the base decline is

17

lowered due to relatively less natural gas development, higher investment in lower decline oil projects and a larger share of higher growth, lower decline projects in the asset mix.

Let me now share some of the highlights of the program for this year, beginning with the water floods.  In the LA Basin, we plan to spend $500 million in the Wilmington and Huntington Beach Fields.  Our Wilmington Field development in 2013 exceeded expectations.  We drilled 135 wells and will increase that 7% to 145 wells in 2014.  Our horizontal program was particularly strong, and horizontal wells will represent an even greater percentage of wells in 2014.

In our Huntington Beach redevelopment, we successfully brought online our two new fit-for-purpose drilling rigs and drilled and completed our first two wells in the project. In 2014, we plan to drill 30 wells and will ultimately drill at least 128 wells.

Our Heavy Oil business unit was a key focus area in 2013 and will be again in 2014.  We plan to spend $350 million to drill about 420 wells, compared to 324 wells in 2013. We’ll also continue the multi-year development of the Kern Front and Lost Hills steam floods and pilot new projects.  I would also like to highlight that the business achieved record production in the fourth quarter, producing 19,000 boepd, an increase of 4,000 boepd from the first quarter of 2013.

At Elk Hills, our key objective is to lower the high decline rate and we have made significant progress toward this goal.  In 2014, we plan to spend $600 million in capital to drill 325 wells, which is an increase of $170 million over 2013. About 55% of Elk Hills capital will be targeting our shale reservoirs where our capital efficiency efforts in 2013 had a significant impact.  We experienced an average of 23% decline in well costs for these

18

programs and 21% decline in operating costs, which dramatically improved the economics and increased the opportunity set.  For example, a typical well that generated 30% IRR prior to our efficiency initiatives now delivers 50% IRR using the same product prices.  In 2014, we will drill around 130 shale wells at Elk Hills, an increase from 80 in 2013.  The remaining Elk Hills capital will target continued development in the shallow oil zone and Stevens sands.

California Exploration

Our California Exploration program has delivered solid results for over 5 years.  The 2014 California program will continue to explore both unconventional and conventional targets.  The unconventional program targets several prospects similar to the 2013 discovery.  The conventional program will target prospects in and around our existing production in both the San Joaquin Valley and Ventura County.  Our extensive proprietary 3D seismic surveys are yielding an exciting inventory of leads and prospects, which will provide years of drilling opportunities.

Lastly, I would like to give you some perspectives on our development plans over the next several years in California.  We expect to continue the capital strategy we initiated in 2013, the shift to lower decline and lower risk steam and water flood projects.  We believe we can grow our California production from 154 mboepd currently to 190 mboepd in 2016, or roughly a 7.5% compound annual growth rate.  Our steam and water flood projects will contribute 80% of that growth.  In fact, 90% will come from projects that are already online.  We think this positions California as one of the lowest risk growth profiles in the industry.  Further, we are targeting

19

primarily oil drilling, which will make our portfolio more oily, contributing to solid margin expansion going forward.  We expect to grow our oil volumes by roughly a 15% compound annual growth rate through 2016.  Over the long-term, we expect our California growth prospects to benefit from changes in our asset mix.  Elk Hills and THUMS, while having the potential for years of continued production, have lower growth prospects due to the mature state of both of those fields.  On the other hand, our water and steam floods, as well as unconventional opportunities, should continue to give us double digit growth for years to come.  The share of our production from Elk Hills and THUMS has shrunk from 64% in 2009 to 44% in 2013.  This shift will continue going forward and the larger share of higher growth projects will further accelerate the growth rate in coming years.

As in the Permian Basin, we are continuing to test new ideas to further improve our drilling, completion and development efficiency in all of our projects.  We are also working diligently to comply with the new regulatory requirements created as a result of the passage of Senate Bill 4 in California.  We have a dedicated team addressing the associated issues and currently we don’t expect significant delays in our development plans.

As you can see, while the Permian Basin and California stories are different, they are both very exciting.  The hard work and dedication of our people have put both of these assets in a position for continued success and 2014 is the year both of these businesses will begin to accelerate their growth as we have completed the transition to a focused growth oriented development program and are set for long-term growth.

I will now turn the call back to Chris Stavros.

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Occidental Petroleum Corporation

CYNTHIA L. WALKER

Executive Vice President and Chief Financial Officer

– Conference Call –

Fourth Quarter 2013 Earnings Announcement

January 30, 2014

Houston, Texas

I will begin with several highlights from the quarter and the year.  In the quarter, we produced 270,000 barrels of oil domestically, which resulted in second half growth of 7,000 barrels per day over the first half average, in line with our previous guidance and setting a new company record.  We continue to be the largest oil producer onshore in the U.S.  Total company production was 750,000 BOE per day, impacted by severe weather and plant turnarounds domestically and continued regional disruptions internationally.  We exceeded the goals we set for the year for operating costs and capital efficiency.  Our oil and gas operating costs were $13.76 for the twelve months of 2013, an improvement of over 8 percent from the 2012 total year rate. Domestic capital efficiency savings were 24 percent, exceeding our goal of 15 percent.  We had core earnings of $1.4 billion or $1.72 per diluted share for the fourth quarter and $5.6 billion or $6.95 per diluted share for the twelve months of 2013.  For the twelve months of 2013, we generated $12.3 billion of cash flow from operations before changes in working capital, we

21

repurchased 10.6 million shares and retired $690 million of debt and ended the year with $3.4 billion of cash on our balance sheet.

Turning to earnings more specifically, core income was approximately $1.4 billion or $1.72 per diluted share.  Compared to the third quarter of 2013, the current quarter results reflected lower oil and gas core earnings driven primarily by lower realized oil prices, seasonally lower earnings in the Chemical segment and reduced core performance in the midstream segment driven by lower margins in the marketing and trading businesses, largely due to commodity price movements.

Now, I will discuss the segment performance for the oil and gas business.  Oil and gas core earnings for the fourth quarter of 2013 were $2.1 billion, a decrease from both the third quarter of 2013 and the fourth quarter of 2012.  On a sequential quarter-over-quarter basis, the decline in earnings resulted primarily from lower domestic oil prices, partially offset by higher oil prices in MENA.  Our sales volumes improved as we recouped the underlifting to date in Iraq, although unrest in Colombia delayed a lifting until the first quarter.  Operating costs mainly in the Middle East/North Africa increased with the increased volume lifted in Iraq.

Total production for the quarter was 750,000 barrels per day, representing decreases of 17,000 barrels from the third quarter and 29,000 barrels from the year ago quarter.  On a sequential quarterly basis, these results reflect domestic growth in California offset by severe weather interruptions in the Permian and Midcontinent regions and the conclusion of the final plant turnarounds in the Permian.  The severe weather caused significant damage to infrastructure and logistics capability that has continued to somewhat impact production in January.  We expect a return to normal operations with no effect on production in February.  MENA

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production was lower primarily due to contract effects in Oman and field and port strikes in Libya.  In addition, insurgent activity in Colombia negatively impacted production by about 3,000 barrels per day.  On a year-over-year basis, full cost recovery and other adjustments under our production sharing and similar contracts, reduced total company production by 12,000 barrels per day.

Our domestic production was 470,000 barrels per day, a decrease of 6,000 barrels per day from the third quarter of 2013 and 5,000 barrels per day from the fourth quarter of 2012.  While we experienced a number of unanticipated impacts this quarter, we are very pleased with how our oil-directed capital program finished the year.  We grew oil production 3,000 barrels from the third quarter, driven mainly by California.  We achieved our previous guidance even with the impact of the severe winter weather.  For the twelve months of 2013, our domestic oil production has increased by 11,000 barrels per day or 4 percent versus 2012.  This growth will accelerate in 2014.  NGL production decreased 6,000 barrels per day in the fourth quarter versus the third quarter, almost entirely in the Permian, resulting primarily from the final plant turnarounds which were concluded in November and third-party facility disruptions.  Natural gas volumes were lower by about 19 mmcf per day compared with the third quarter, with nearly the entire decline coming from the Midcontinent area.

Turning to realized prices, compared with the third quarter, our worldwide crude oil realized price decreased about 4 ½ percent, primarily reflecting changes in benchmark prices.  We experienced improvement in NGL pricing domestically which contributed to a 10 percent increase in worldwide NGL realized prices, while domestic natural gas realized prices experienced a 2 percent increase driven by improvement in the benchmark.

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We also included updated price sensitivities in the conference call materials available on our website.

Oil and gas production costs were $14.13 per barrel in the fourth quarter and $13.76 for the twelve months of 2013, compared to $14.99 per barrel for the full year of 2012.  Domestic operating expenses remained about flat from the third quarter of 2013.  International production costs increased in the fourth quarter due to higher liftings in Iraq, which have high operating costs.

Taxes other than on income, which are generally related to product prices, were $2.57 per barrel for the twelve months of 2013, compared with $2.39 per barrel for the full year of 2012.

Fourth quarter exploration expense was $60 million.  We expect first quarter 2014 exploration expense to be about $80 million.

Turning to Chemical segment core earnings, fourth quarter earnings of $128 million were $53 million lower than the third quarter, primarily driven by lower caustic soda and PVC pricing and seasonal factors.  We expect first quarter 2014 earnings to be $100 million.  Lower caustic soda pricing and higher energy and ethylene costs going into the year are the primary drivers for the decrease in segment earnings versus the fourth quarter of 2013.

Midstream segment earnings, which were $68 million for the fourth quarter of 2013, compared to $212 million in the third quarter of 2013 and $75 million in the fourth quarter of 2012.  The 2013 sequential quarterly decline in earnings resulted mainly from lower marketing and trading performance, driven by commodity price movements during the quarter, and lower margins in our power generation and gas processing businesses which were negatively impacted by the plant turnarounds in the fourth quarter.

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The worldwide effective tax rate on core income was 37 percent for the fourth quarter of 2013.  We expect our combined worldwide tax rate in the first quarter of 2014 to be in the 40 to 41 percent range.

In the twelve months of 2013, we generated $12.3 billion of cash flow from operations before changes in working capital.  Working capital changes increased our cash flow from operations by $600 million to $12.9 billion.  Capital expenditures for the full year of 2013 were $8.8 billion, of which $2.4 billion was spent in the fourth quarter.  We generated approximately $1.4 billion of cash from the fourth quarter sale of a portion of the Company’s interest in the General Partner of Plains All-American Pipeline and $270 million of cash from the sale of a Chemical investment earlier in the year and used $645 million for acquisitions of domestic oil and gas assets.  After paying dividends of $1.6 billion, buying back $945 million of Company stock, retiring debt of nearly $700 million and other net flows, our cash balance was $3.4 billion at December 31.  Our debt-to-capitalization ratio declined to 14 percent at year-end from 16 percent at year-end 2012.  Our 2013 return on equity was 14 percent and return on capital employed was around 12 percent.

Lastly, I will outline our expectations for 2014.  This will be based on our current portfolio of assets.  As we announce the potential transactions we have discussed in the past, we will update our expectations as appropriate.

2014 Capital Program

Our 2014 capital program is expected to be about $10.2 billion.  The 2014 program breakdown is 80 percent in Oil and Gas, 7 percent in the Al Hosn gas project, 7 percent in domestic Midstream and the remainder in Chemicals.  As with 2013, a higher than typical portion of our capital will be

25

spent on long-term projects in 2014.  We expect that about 20% of our total capital expenditures will be on projects that will make significant contribution to earnings and cash flow in future years.  Although with the start-up of Al Hosn, BridgeTex and New Johnsonville this year, this proportion should reduce meaningfully next year.

Further details on the mix of our 2014 and 2013 capital spending programs by geographical area:

—	Domestic oil and gas development capital will be about 49 percent of our total capital program.
		○	We expect to average about 61 operated rigs versus 50 in 2013.  The increase will be driven primarily by increased spending in California.  In the Permian, our rig count will increase only slightly as we swap horizontal rigs for vertical rigs.
		○	Our total domestic oil and gas capital is expected to increase by about $800 million.  Permian and California should each increase about $400 million on a year-over-year basis.  The Midcontinent will remain flat at around $900 million.
		○	Our capital will continue to be directed to oil projects, and this will be the biggest driver of growth in 2014.
—	Internationally;
		○	Our total Al Hosn gas project capital should decline about 20 percent from the 2013 levels, and will make up about 7 percent of our total capital program for the year.
		○	Qatar capital spending is expected to increase about $200 million for the North Dome Phase V development plan.
—	Exploration capital spending should increase about 35 percent from the 2013 spending levels and represent about 6 percent of the total

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	capital program.  The focus of the program domestically will be in the Permian basin and California, with additional international drilling in Bahrain and Oman.
—	The U.S. Midstream capital will increase about $200 million to approximately $700 million as we spend to complete the BridgeTex pipeline project, which is scheduled to be operational in the second-half of 2014, and to begin construction of an LPG export terminal and crude terminal at Ingleside.
—	Chemical segment capital will be about $500 million, which includes the Ingleside Ethylene cracker scheduled to begin construction in the third quarter of 2014.

2014 Production

Overall, we expect production to be between 780,000 and 790,000 BOE per day in 2014.  Domestically, we expect oil production for all of 2014 to grow to a range of 280,000 to 295,000  BOE per day, or approximately 9%.  We expect NGL volumes to be relatively flat with 2013 levels, and continued modest natural gas production declines resulting from limited drilling.  Production in the first quarter should be about flat to the fourth quarter and should grow fairly evenly through the year as activity builds and we execute our program.

Internationally, at current prices and excluding Libya, we expect total production to be about 5,000 BOE per day higher in the first quarter and flat for the remainder of the year.  We expect a fourth quarter start-up of the Al Hosn gas project, and any resulting production would be in addition.

We expect our 2014 production costs to remain around $14.00 per barrel, and our DD&A expense to be around $17.40 per barrel.

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Occidental Petroleum Corporation
Return on Capital Employed (ROCE)
For the Twelve Months Ended December 31,
Reconciliation to Generally Accepted Accounting Principles (GAAP)
	2012		2013
RETURN ON CAPITAL EMPLOYED (%)	10.3%		12.2%
GAAP measure - net income	4,598		5,903
Interest expense	117		110
Tax effect of interest expense	(41	)	(39	)
Earnings before tax-effected interest expense	4,674		5,974
GAAP stockholders' equity	40,048		43,372
Debt	7,623		6,939
Total capital employed	47,671		50,311

EX-99.3

EXHIBIT 99.3

Investor Relations Supplemental Schedules

Investor Relations Supplemental Schedules
Summary
	4Q 2013	4Q 2012
Core Results (millions)	$1,379	$1,479
EPS - Diluted	$1.72	$1.83
Reported Net Income (millions)	$1,643	$336
EPS - Diluted	$2.04	$0.42
Total Worldwide Sales Volumes (mboe/day)	772	784
Total Worldwide Production Volumes (mboe/day)	750	779
Total Worldwide Crude Oil Realizations ($/BBL)	$99.27	$96.19
Total Worldwide NGL Realizations ($/BBL)	$44.69	$45.08
Domestic Natural Gas Realizations ($/MCF)	$3.33	$3.09
Wtd. Average Basic Shares O/S (millions)	801.7	807.1
Wtd. Average Diluted Shares O/S (millions)	802.1	807.7
	YTD 2013	YTD 2012
Core Results (millions)	$5,602	$5,750
EPS - Diluted	$6.95	$7.09
Reported Net Income (millions)	$5,903	$4,598
EPS - Diluted	$7.32	$5.67
Total Worldwide Sales Volumes (mboe/day)	762	764
Total Worldwide Production Volumes (mboe/day)	763	766
Total Worldwide Crude Oil Realizations ($/BBL)	$99.84	$99.87
Total Worldwide NGL Realizations ($/BBL)	$41.03	$45.18
Domestic Natural Gas Realizations ($/MCF)	$3.37	$2.62
Wtd. Average Basic Shares O/S (millions)	804.1	809.3
Wtd. Average Diluted Shares O/S (millions)	804.6	810.0
Shares Outstanding (millions)	796.0	805.5
Cash Flow from Operations (millions)	$12,900	$11,300

1

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
2013 Fourth Quarter
Net Income (Loss)
($ millions, except per share amounts)
	Reported							Core
	Income			Significant Items Affecting Income				Results
Oil & Gas	$	1,511		$	607		Asset impairments	$	2,118
Chemical		128							128
Midstream, marketing and other		1,098			(1,030	)	Plains Pipeline sale gain and other		68
Corporate
Interest expense, net		(23	)						(23	)
Other		(93	)						(93	)
Taxes		(973	)		154		Tax effect of pre-tax adjustments		(819	)
Income from continuing operations		1,648			(269	)			1,379
Discontinued operations, net of tax		(5	)		5		Discontinued operations, net		-
Net Income	$	1,643		$	(264	)		$	1,379
Basic Earnings Per Common Share
Income from continuing operations	$	2.05
Discontinued operations, net		(0.01	)
Net Income	$	2.04						$	1.72
Diluted Earnings Per Common Share
Income from continuing operations	$	2.05
Discontinued operations, net		(0.01	)
Net Income	$	2.04						$	1.72

2

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
2012 Fourth Quarter
Net Income (Loss)
($ millions, except per share amounts)
	Reported							Core
	Income			Significant Items Affecting Income				Results
Oil & Gas	$	522		$	1,731		Asset impairments and related items	$	2,253
Chemical		180							180
Midstream, marketing and other		75							75
Corporate
Interest expense, net		(30	)						(30	)
Other		(134	)		20		Litigation reserves		(114	)
Taxes		(249	)		(636	)	Tax effect of adjustments		(885	)
Income from continuing operations		364			1,115				1,479
Discontinued operations, net of tax		(28	)		28		Discontinued operations, net		-
Net Income	$	336		$	1,143			$	1,479
Basic Earnings Per Common Share
Income from continuing operations	$	0.45
Discontinued operations, net		(0.03	)
Net Income	$	0.42						$	1.83
Diluted Earnings Per Common Share
Income from continuing operations	$	0.45
Discontinued operations, net		(0.03	)
Net Income	$	0.42						$	1.83

3

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
2013 Twelve Months
Net Income (Loss)
($ millions, except per share amounts)
	Reported							Core
	Income			Significant Items Affecting Income				Results
Oil & Gas	$	7,894		$	607		Asset impairments	$	8,501
Chemical		743			(131	)	Carbocloro sale gain		612
Midstream, marketing and other		1,573			(1,030	)	Plains Pipeline sale gain and other		543
Corporate
Interest expense, net		(110	)						(110	)
Other		(423	)		55		Charge for former executives and consultants (a)		(368	)
Taxes		(3,755	)		179		Tax effect of pre-tax adjustments		(3,576	)
Income from continuing operations		5,922			(320	)			5,602
Discontinued operations, net of tax		(19	)		19		Discontinued operations, net		-
Net Income	$	5,903		$	(301	)		$	5,602
Basic Earnings Per Common Share
Income from continuing operations	$	7.35
Discontinued operations, net		(0.02	)
Net Income	$	7.33						$	6.95
Diluted Earnings Per Common Share
Income from continuing operations	$	7.34
Discontinued operations, net		(0.02	)
Net Income	$	7.32						$	6.95
(a) Reflects pre-tax charge for the estimated cost related to the employment and post-employment benefits for the
Company's former Executive Chairman and termination of certain other employees and consulting arrangements.

4

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
2012 Twelve Months
Net Income (Loss)
($ millions, except per share amounts)
	Reported							Core
	Income			Significant Items Affecting Income				Results
Oil & Gas	$	7,095		$	1,731		Asset impairments and related items	$	8,826
Chemical		720							720
Midstream, marketing and other		439							439
Corporate
Interest expense, net		(117	)						(117	)
Other		(384	)		20		Litigation reserves		(364	)
Taxes		(3,118	)		(636	)	Tax effect of adjustments		(3,754	)
Income from continuing operations		4,635			1,115				5,750
Discontinued operations, net of tax		(37	)		37		Discontinued operations, net		-
Net Income	$	4,598		$	1,152			$	5,750
Basic Earnings Per Common Share
Income from continuing operations	$	5.72
Discontinued operations, net		(0.05	)
Net Income	$	5.67						$	7.09
Diluted Earnings Per Common Share
Income from continuing operations	$	5.71
Discontinued operations, net		(0.04	)
Net Income	$	5.67						$	7.09

5

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
Worldwide Effective Tax Rate
	QUARTERLY						YEAR-TO-DATE
	2013		2013		2012		2013		2012
REPORTED INCOME	QTR 4		QTR 3		QTR 4		12 Months		12 Months
Oil & Gas	1,511		2,363		522		7,894		7,095
Chemical	128		181		180		743		720
Midstream, marketing and other	1,098		212		75		1,573		439
Corporate & other	(116	)	(131	)	(164	)	(533	)	(501	)
Pre-tax income	2,621		2,625		613		9,677		7,753
Income tax expense
Federal and state	517		461		(293	)	1,602		694
Foreign	456		576		542		2,153		2,424
Total	973		1,037		249		3,755		3,118
Income from continuing operations	1,648		1,588		364		5,922		4,635
Worldwide effective tax rate	37%		40%		41%		39%		40%
	2013		2013		2012		2013		2012
CORE RESULTS	QTR 4		QTR 3		QTR 4		12 Months		12 Months
Oil & Gas	2,118		2,363		2,253		8,501		8,826
Chemical	128		181		180		612		720
Midstream, marketing and other	68		212		75		543		439
Corporate & other	(116	)	(131	)	(144	)	(478	)	(481	)
Pre-tax income	2,198		2,625		2,364		9,178		9,504
Income tax expense
Federal and state	363		461		343		1,447		1,330
Foreign	456		576		542		2,129		2,424
Total	819		1,037		885		3,576		3,754
Core results	1,379		1,588		1,479		5,602		5,750
Worldwide effective tax rate	37%		40%		37%		39%		39%

6

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
2013 Fourth Quarter Net Income (Loss)
Reported Income Comparison
	Fourth			Third
	Quarter			Quarter
	2013			2013			B / (W)
Oil & Gas	$	1,511		$	2,363		$	(852	)
Chemical		128			181			(53	)
Midstream, marketing and other		1,098			212			886
Corporate
Interest expense, net		(23	)		(28	)		5
Other		(93	)		(103	)		10
Taxes		(973	)		(1,037	)		64
Income from continuing operations		1,648			1,588			60
Discontinued operations, net		(5	)		(5	)		-
Net Income	$	1,643		$	1,583		$	60
Earnings Per Common Share
Basic	$	2.04		$	1.96		$	0.08
Diluted	$	2.04		$	1.96		$	0.08
Worldwide Effective Tax Rate		37%			40%			3%
OCCIDENTAL PETROLEUM
2013 Fourth Quarter Net Income (Loss)
Core Results Comparison
	Fourth			Third
	Quarter			Quarter
	2013			2013			B / (W)
Oil & Gas	$	2,118		$	2,363		$	(245	)
Chemical		128			181			(53	)
Midstream, marketing and other		68			212			(144	)
Corporate
Interest expense, net		(23	)		(28	)		5
Other		(93	)		(103	)		10
Taxes		(819	)		(1,037	)		218
Core Results	$	1,379		$	1,588		$	(209	)
Core Results Per Common Share
Basic	$	1.72		$	1.97		$	(0.25	)
Diluted	$	1.72		$	1.97		$	(0.25	)
Worldwide Effective Tax Rate		37%			40%			3%

7

Investor Relations Supplemental Schedules

8

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
2013 Fourth Quarter Net Income (Loss)
Reported Income Comparison
	Fourth			Fourth
	Quarter			Quarter
	2013			2012			B / (W)
Oil & Gas	$	1,511		$	522		$	989
Chemical		128			180			(52	)
Midstream, marketing and other		1,098			75			1,023
Corporate
Interest expense, net		(23	)		(30	)		7
Other		(93	)		(134	)		41
Taxes		(973	)		(249	)		(724	)
Income from continuing operations		1,648			364			1,284
Discontinued operations, net		(5	)		(28	)		23
Net Income	$	1,643		$	336		$	1,307
Earnings Per Common Share
Basic	$	2.04		$	0.42		$	1.62
Diluted	$	2.04		$	0.42		$	1.62
Worldwide Effective Tax Rate		37%			41%			4%
OCCIDENTAL PETROLEUM
2013 Fourth Quarter Net Income (Loss)
Core Results Comparison
	Fourth			Fourth
	Quarter			Quarter
	2013			2012			B / (W)
Oil & Gas	$	2,118		$	2,253		$	(135	)
Chemical		128			180			(52	)
Midstream, marketing and other		68			75			(7	)
Corporate
Interest expense, net		(23	)		(30	)		7
Other		(93	)		(114	)		21
Taxes		(819	)		(885	)		66
Core Results	$	1,379		$	1,479		$	(100	)
Core Results Per Common Share
Basic	$	1.72		$	1.83		$	(0.11	)
Diluted	$	1.72		$	1.83		$	(0.11	)
Worldwide Effective Tax Rate		37%			37%			0%

9

Investor Relations Supplemental Schedules

10

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
SUMMARY OF OPERATING STATISTICS
		Fourth Quarter		Twelve Months
		2013	2012	2013	2012
NET PRODUCTION PER DAY:
United States
Oil (MBBL)
	California	94	92	90	88
	Permian	146	146	146	142
Midcontinent and other		30	27	30	25
	Total	270	265	266	255
NGLs (MBBL)
	California	20	21	20	17
	Permian	36	40	39	39
Midcontinent and other		17	16	18	17
	Total	73	77	77	73
Natural Gas (MMCF)
	California	260	242	260	256
	Permian	147	162	157	155
Midcontinent and other		355	396	371	410
	Total	762	800	788	821
Latin America
Oil (MBBL)	Colombia	29	30	29	29
Natural Gas (MMCF)	Bolivia	12	12	12	13
Middle East / North Africa
Oil (MBBL)
	Dolphin	7	7	6	8
	Oman	64	74	66	67
	Qatar	69	71	68	71
	Other	29	40	39	40
	Total	169	192	179	186
NGLs (MBBL)	Dolphin	7	7	7	8
	Other	-	-	-	1
	Total	7	7	7	9
Natural Gas (MMCF)
	Dolphin	145	138	142	163
	Oman	42	56	51	57
	Other	253	242	241	232
	Total	440	436	434	452
Barrels of Oil Equivalent (MBOE)		750	779	763	766

11

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
SUMMARY OF OPERATING STATISTICS
		Fourth Quarter		Twelve Months
		2013	2012	2013	2012
NET SALES VOLUMES PER DAY:
United States
Oil (MBBL)		270	265	266	255
NGLs (MBBL)		73	77	77	73
Natural Gas (MMCF)		762	800	789	819
Latin America
Oil (MBBL)		23	30	27	28
Natural Gas (MMCF)		12	12	12	13
Middle East / North Africa
Oil (MBBL)
	Dolphin	7	7	6	8
	Oman	65	70	68	66
	Qatar	66	75	67	71
	Other	59	43	38	40
	Total	197	195	179	185
NGLs (MBBL)	Dolphin	7	7	7	8
	Other	-	2	-	1
		7	9	7	9
Natural Gas (MMCF)		440	436	434	452
Barrels of Oil Equivalent (MBOE)		772	784	762	764

12

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
SUMMARY OF OPERATING STATISTICS
	Fourth Quarter				Twelve Months
	2013		2012		2013		2012
OIL & GAS:
REALIZED PRICES
United States
Oil ($/BBL)		94.52		87.81		96.42		93.72
NGLs ($/BBL)		45.72		44.54		41.80		46.07
Natural gas ($/MCF)		3.33		3.09		3.37		2.62
Latin America
Oil ($/BBL)		99.77		97.95		103.21		98.35
Natural gas ($/MCF)		10.58		11.56		11.17		11.85
Middle East / North Africa
Oil ($/BBL)		105.83		107.50		104.48		108.76
NGLs ($/BBL)		35.01		49.14		33.00		37.74
Total Worldwide
Oil ($/BBL)		99.27		96.19		99.84		99.87
NGLs ($/BBL)		44.69		45.08		41.03		45.18
Natural gas ($/MCF)		2.47		2.35		2.54		2.06
INDEX PRICES
WTI oil ($/BBL)		97.46		88.18		97.97		94.21
Brent oil ($/BBL)		109.35		110.08		108.76		111.70
NYMEX gas ($/MCF)		3.64		3.37		3.66		2.81
REALIZED PRICES AS PERCENTAGE OF INDEX PRICES
Worldwide oil as a percentage of WTI		102%		109%		102%		106%
Worldwide oil as a percentage of Brent		91%		87%		92%		89%
Worldwide NGLs as a percentage of WTI		46%		51%		42%		48%
Domestic natural gas as a percentage of NYMEX		92%		92%		92%		93%
	Fourth Quarter				Twelve Months
	2013		2012		2013		2012
Exploration Expense
United States	$	50	$	46	$	187	$	232
Latin America		1		1		6		2
Middle East / North Africa		9		35		63		111
	$	60	$	82	$	256	$	345

13

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
SUMMARY OF OPERATING STATISTICS
		Fourth Quarter					Twelve Months
Capital Expenditures ($MM)		2013			2012		2013			2012
Oil & Gas
California		$	457		$	382	$	1,533		$	2,029
Permian			435			424		1,722			1,920
Midcontinent and other			260			204		901			1,324
Latin America			103			124		339			309
Middle East  / North Africa			519			638		2,120			2,016
Exploration			143			108		430			622
Chemical			125			165		424			357
Midstream, marketing and other			425			440		1,404			1,558
Corporate			19			25		164			91
	TOTAL		2,486			2,510		9,037			10,226
Non-controlling interest contributions			(67	)		-		(212	)		-
Cracker JV contribution			23			-		23			-
		$	2,442		$	2,510	$	8,848		$	10,226
Depreciation, Depletion &		Fourth Quarter					Twelve Months
Amortization of Assets ($MM)		2013			2012		2013			2012
Oil & Gas
Domestic		$	745		$	628	$	2,967		$	2,412
Latin America			20			31		107			117
Middle East  / North Africa			534			385		1,679			1,404
Chemical			86			88		346			345
Midstream, marketing and other			58			52		212			206
Corporate			8			7		36			27
	TOTAL	$	1,451		$	1,191	$	5,347		$	4,511

14

Investor Relations Supplemental Schedules

OCCIDENTAL PETROLEUM
CORPORATE
($ millions)
	31-Dec-13			31-Dec-12
CAPITALIZATION
Long-Term Debt (including current maturities)		$	6,939		$	7,623
EQUITY		$	43,372		$	40,048
Total Debt To Total Capitalization			14%			16%

15

EX-99.4

EXHIBIT 99.4

Occidental Petroleum Corporation

Fourth Quarter 2013 Earnings Conference Call

January 30, 2014

1

2

Fourth Quarter 2013 Earnings - 2013 Highlights

ØGrew our domestic oil production last year by 11 mb/d
over 2012 to 266 mb/d.

ØExceeded our capital efficiency goals by reducing drilling
costs by ~24% from the 2012 level.

ØReduced our domestic operating costs by 17%.

ØAdded ~470 MMBOE of reserves achieving an overall
replacement ratio of 169%.

ØTotal costs incurred associated with reserve adds were ~$7.7 billion
resulting in an apparent F&D <$17 / boe.

ØIncreased ROCE from 10.3% in 2012 to 12.2% in 2013.

2

Fourth Quarter 2013 Earnings -
2013 Development Program Review

•Improved capital efficiency by 24% over
2012 in the US, saving $900 mm of capital.

–Permian - 50% of improvement

–California - 25% of improvement

–Other Domestic Assets - 25% of improvement

•Successfully completed drilling program
and by drilling approximately what we had
planned.

•Reduced domestic operating costs by
17% or $470 mm compared to 2012.

–Permian - 48% of improvement

–California - 46% of improvement

–Other Domestic Assets - 6% of improvement

•Grew domestic oil production by 11 mb/d.

3

Domestic Oil Production

255

266

Domestic Operating Costs

3

4

Fourth Quarter 2013 Earnings - Oil & Gas Reserves

•Very successful year in growing the Company’s reserve base, by
adding substantially more reserves than we produced, over 90%
of which was added through our organic development program.

•Based on a preliminary estimate of year-end 2013 reserve levels:

−Ended 2013 with ~3.5 B barrels of reserves, an all-time high for Oxy.

−Total reserve replacement ratio from all categories before dispositions
was ~168%, or ~470 MMBOE of new reserves, compared with ~278 MMBOE
of 2013 production.

−In the U.S., reserve replacement ratio was ~190%.

−Replacement ratios of the California and Permian non-CO2 properties were
similar to the overall company ratio.

−Reserve replacement ratio for liquids from all categories was 195% for the
total company and 228% domestically; reflects our emphasis on oil drilling.

•Total costs incurred related to the total reserve additions for
the year, on a preliminary basis, were ~$7.7 billion.

4

5

Fourth Quarter 2013 Earnings - Oil & Gas Reserves

(in millions of BOE)

2013 Overall Reserve
Replacement Ratio of
~169%

* Preliminary

5

6

Fourth Quarter 2013 Earnings - Oil & Gas Reserves

•Built a large portfolio of growth oriented assets in the U.S.

•In 2013, we spent a much larger portion of our investment
dollars on the development of this portfolio.

•Our organic reserve replacement for 2013 reflects the
positive results of the development program:

−Our 2013 development program, excluding acquisitions, replaced
~169% of our domestic production with ~291 MMBOE of reserve adds.

−In addition, we transferred ~115 MMBOE of proved undeveloped
reserves to the proved developed category domestically as a result
of the 2013 development program.

−2013 acquisitions were at a multi-year low of $550 mm providing
reserve additions of 32 MMBOE.

6

7

Fourth Quarter 2013 Earnings -
U.S. Oil & Gas Reserves

(in millions of BOE)

2013 U.S. Reserve
Replacement Ratio of
~190%

* Preliminary

7

8

Fourth Quarter 2013 Earnings - Oil & Gas Reserves

•At year end 2013, ~73% of total proved reserves were liquids,
increasing from 72% in 2012.

–Of the total reserves, ~70% were proved developed reserves, compared
to 73% in 2012.

−Increase in the share of proved undeveloped reserves compared to
2012 was the result of reserves added for the Al Hosn Gas Project.

−We expect to move these reserves to the proved developed category
at the end of this year once initial production starts in 4Q14.

•Through success of our drilling program and capital efficiency
initiatives, we lowered our F&D costs over recent years.

•As a result, we expect our DD&A expense to be ~$17.40 per
barrel in 2014, only a small increase from $17.10 in 2013.

−Consistent with our expectations that the DD&A rate of growth should
flatten out as recent investments come online and F&D costs come down.

8

9

Fourth Quarter 2013 Earnings - Oil & Gas Reserves

•Success of our organic reserve additions and the efficiencies
we have achieved in our operations demonstrates the
significant progress we have made in turning the Company
into a competitive domestic producer.

•One of our long-term goals domestically has been to achieve
a 50% pretax margin after F&D and cash operating costs to
generate solid returns.

•We believe we are achieving that now and expect to continue
to do so going forward.

9

10

Fourth Quarter 2013 Earnings - ROCE

•Our focus in 2013 was to enhance
shareholder value through our results.

•Heavily focused on growing domestic
oil production, improving our capital
efficiency and F&D costs and lowering
our operating costs.

•We met or exceeded all of these goals
and as a result, we increased our ROCE
to 12.2%, a significant improvement
from the 10.3% level in 2012.

•Expect to see further improvement in
our returns in coming years as a result of
recent investments.

•Our 2014 program is designed to
continue and improve upon last
year’s strong performance.

Return on Capital Employed *

* See GAAP Reconciliation

10

Fourth Quarter Earnings -
Capital Spending 2013 Actual & 2014 Estimate

•2014 capital program expected to be ~$10.2 billion*

11

$8.8

$10.2

•Increase in capital includes ~$400 mm
allocated to each of our CA and Permian
operations largely for additional drilling
to accelerate their development plans
and production growth.

•An additional $100 mm will be spent in
these and other U.S. assets for facilities
projects that were deferred from 2013.

•The domestic oil and gas program will
focus on growing oil production and the
entire increase in capital will go to oil
projects.

•Continue to fund growth opportunities in
key international assets, mainly in Oman
and Qatar ($300 mm of additional capital),
and will complete the Al Hosn Gas Project.

•Exploration capital will increase ~$100 mm.

*Does not reflect any of the effects of our Strategic Review initiatives.

Capital Investment ($ bln)

11

Fourth Quarter Earnings -
Capital Spending 2013 Actual & 2014 Estimate

12

*Does not reflect any of the effects of our Strategic Review initiatives.

12

13

Fourth Quarter 2013 Earnings -
2014 Production Outlook

•We expect our 2014 total company
production volumes to grow to
780 - 790 mboe/d vs. 763 mboe/d in
2013, with a 4Q14 exit rate of over
800 mboe/d, excluding the planned
Al Hosn production.

•This increase will come almost entirely
from domestic oil production while we
expect to see a continued modest drop
in our domestic gas volumes.

•Domestic oil production is expected
to grow from 266 mb/d in 2013 to
280 - 295 mb/d in 2014, or ~9%.

•This growth will come fairly evenly
from our CA and Permian operations.

•Internationally, excluding Al Hosn,
we expect production to grow slightly.

763

780 - 790

Domestic Oil*

266

280 - 295

Total Company*

*Does not reflect any of the effects of our Strategic Review initiatives.

13

14

Fourth Quarter 2013 Earnings -
2014 Production Outlook

•While the elements of the 2014 program as discussed
assume no changes to the Company structure or its mix
of assets, we do expect the Company to look significantly
different by the end of the year.

•The strategic review we are undertaking will result in
significant changes to the Company’s asset mix.

•Our capital program, production expectations and other
elements of the 2014 program will be adjusted as related
transactions are concluded.

14

15

Fourth Quarter 2013 Earnings -
Long-term Growth Investments

•Some of the longer lead time investments we have been
making over the past couple of years will start contributing
to our results this year.

Specifically:

ØThe Al Hosn Gas Project is expected to start its initial
production in 4Q’14 and start contributing to our cash flow.

ØWe expect the BridgeTex pipeline to come online around
3Q’14 and start contributing to our Midstream earnings
and cash flow.

ØThe New Johnsonville chlor-alkali plant is expected to come
online early in the year and will make a positive contribution
to the operations of our chemical business.

15

Fourth Quarter 2013 Earnings - Strategic Review

16

•With respect to the initiatives outlined in the first phase
of the Company’s strategic review announced last year:

−We completed the sale of a portion of the Company’s investment in
the General Partner of the Plains All-American Pipeline in October
resulting in pre-tax proceeds of $1.4 billion.After this sale, we continue
to hold a ~25% interest, which at current market prices would be valued
at ~$3.7 billion.

−We have made steady progress on discussions with key partners in the
countries we operate in the MENA region for the sale of a minority interest
in our operations there.Due to the scale and complexities of a potential
transaction, we expect these discussions to continue through 1H’14.

−We have also made good progress in our pursuit of strategic alternatives
for select Midcontinent assets.We expect to provide further information
on any transactions as they conclude around the end of 2Q’14 and will
announce material developments as they occur.

16

17

Fourth Quarter 2013 Earnings - Capitalization

•In 4Q’13, we used the Plains proceeds to retire $625 mm of
debt, reducing our debt load by ~9%, and to purchase almost
10 mm shares of the Company’s stock with a cash outlay of
$880 mm.

Shares Outstanding (mm)FY201312/31/13

Weighted Average Basic804.1

Weighted Average Diluted804.6

Shares Outstanding796.0

Capitalization ($mm)12/31/1212/31/13

Long-Term Debt$7,623 $6,939

Equity$ 40,048 $ 43,372

Total Debt to Total Capitalization16%14%

17

Fourth Quarter 2013 Earnings - Summary

18

•At the Board’s February meeting we will review the Company’s
dividend policy, status of the strategic alternatives and share
repurchase authority.

•Many of the steps we have taken in 2013, our success in
improving our efficiency and the actions that our Board
has authorized, lay the groundwork for strong results in
2014 and beyond.

•The operational improvements we expect to achieve in 2014,
coupled with the strategic actions we expect to execute this
year should place the Company in a position to improve its
returns while continuing to grow and increase its dividends
to maximize shareholder value.

18

Fourth Quarter 2013 Earnings -
Permian Basin & California Oil & Gas Operations

2014 Operational Objectives

19

ØContinue the development of anchor projects, enabling the
allocation of significant portions of capital to projects with
solid returns, low execution risk and long-term growth.

ØFurther reduce drilling and completion costs to improve
F&D costs and project economics.

ØContinue to optimize operating costs, without affecting
production, to improve current earnings and free cash flow.

ØBuild on successful exploration efforts in core areas.

ØEvaluate data and test new concepts in pilot areas,
which will set up anchor projects of the future.

19

Fourth Quarter 2013 Earnings - Permian Basin

Permian Basin Capital

20

•Two business units named as:

−“Permian EOR”: CO2 and
waterfloods.

−“Permian Resources”: growth
oriented “unconventional”.

•The entire $450 mm increase
will be spent on our Permian
Resources assets, representing
~70% of total capital in the basin.

$1,722

$2,190

$1,530

$660

$615

$1,107

($ in mm)

20

Fourth Quarter 2013 Earnings - Permian Basin

21

$19.35

$16.13

•We expect the Permian EOR business
to offset its declinein 2014 and grow
1.4%.

•The Permian Resources business is
expected to grow oil production faster
by 20% - 25% and total production by
13% - 16%.

•On a combined basis, should translate to:

−6%+ oil production growth.

−5% total production growth.

−~$1.8 billion cash flow after capital.

•Improved capital efficiency by 25%
and reduced operating expenses by
$3.22 / boe.

211

~222

21

Fourth Quarter 2013 Earnings - Permian Resources

Development Wells

22

•Drilled 49 horizontal wells with
47 completed and producing.

•Improvements in well costs,
our own results and those of
neighboring operators have
given us the confidence to
dramatically shift our program
to more horizontal drilling in
2014.

•2014 Goal: Continue the
evaluation of the potential
across our full acreage position.

•2014 Goal: Pilot various
development strategies, including
optimal lateral length, frac design
and well spacing both laterally
and vertically.

Avg. Rig Count1621

335

~345

Shift to Horizontal Drilling

22

Fourth Quarter 2013 Earnings - Permian Resources

23

•Believe we have one of the most promising and
under-exploited unconventional portfolio in the basin.

•In 2013, added 200K net prospective acres to our
unconventional portfolio, and now have ~1.9 mm
prospective acres.

•Exposure to all unconventional plays, which is
unique and will give us flexibility to develop our
most attractive opportunities first, and mitigate risks.

•Identified ~4,500 drilling locations representing
1.2+ billion net barrels of resource potential.

•Believe we have made conservative assumptions
regarding prospective acres, well spacing and
expected ultimate recoveries and expect these
numbers will grow as we learn more.

Acreage in Select Permian Plays

(Thousands of Acres)

23

Fourth Quarter 2013 Earnings - Permian Resources

24

•We see the largest near-term growth in the
Midland Basin, which represents ~ 2/3 of
our currently assessed resource potential.

•Our Delaware Basin prospective acreage is
significantly larger, and the potential there
should continue to grow.

•We believe our measured approach to our
unconventional portfolio has worked to our
advantage.

•Our Permian Resources production comes
from ~9,500 gross wells, of which 54% are
operated by other producers.On a net basis,
we have 4,400 wells of which only 15% are
non-operated.

•This has given us the opportunity to observe
the results achieved by other operators in
the Basin, learn from those results and
optimize our approach to maximize the
opportunity set on our acreage.

Permian Basin Plays

24

Fourth Quarter 2013 Earnings - Permian Resources

25

•The success of our capital and
operating cost efficiency efforts
in 2013, has also enabled us to
significantly improve our cost
structure which has increased
our opportunity set.

•For example, a typical well in the
Collie area that had IRR of 24%
before our capital and operating
cost reductions, now yields IRR of
48% using the same product prices.

•We achieved similar success in all
of our most active areas across the
business unit.

Resource

Collie

Yeso

Cost Reductions Expand Opportunity Set

25

Fourth Quarter 2013 Earnings- Permian Resources

26

Unconventional Acreage Strategy

1.Exploration to establish the presence
of a commercial resource.

2.Testing and data gathering to optimize
well and completion design.

3.Pilot programs to assess variability
of well performance to design full field
development plans.

4.Transition to manufacturing mode
for full field development.

•Prudent strategy to develop our acreage,
maximizing cash flow and returns.

•We are now prepared to accelerate
our activities in the Permian Resources
business where the opportunity in front
of us is one of the biggest in the basin.

26

Fourth Quarter 2013 Earnings - Permian Resources

27

Midland Basin

2014E Capital	$790 mm
Average Rigs	8
2014 Wells	174
Horizontal Wells	74

•Drilled 16 horizontal wells to date.

•Largest opportunity is in the Wolfcamp
Shale where we have tested Wolfcamp A and
B benches and, plan to test the remainingbenches.

•South Curtis Ranch - average 30 day IP rate
of horizontal wells have met expectations at
~800 boe/d.

•Started full field development mode with
remaining inventory of 200+ horizontal
locations.

•Substantial Cline resource potential with
450+ locations.

•Plan to test horizontal Spraberry in 1Q14.

Texas

Oxy acreage in blue

27

Fourth Quarter 2013 Earnings - Permian Resources

28

Texas Delaware Basin

2014E Capital	$370 mm
Average Rigs	5
2014 Wells	91
Horizontal Wells	48

•Horizontal activity focused on
Wolfcamp where we believe the A,
B and C benches will prove to be
the most prospective.

•Drilled or participated in 3 horizontal
Wolfcamp wells in 2013 and will
increase that to 45 wells in 2014.

•Activity centered in Reeves County.

•Collie program plans to drill 43
vertical wells targeting Bell and
Cherry Canyon formations.

Texas

New Mexico

Oxy acreage in blue

28

Fourth Quarter 2013 Earnings - Permian Resources

29

New Mexico Permian

2014E Capital	$370 mm
Average Rigs	4
2014 Wells	97
Horizontal Wells	50

•Bone Spring formation in New Mexico
is the second largest opportunity in our
portfolio behind the Wolfcamp Shale.

•In 2013, we drilled 16 horizontal wells
testing the 1st, 2nd and 3rdBone Spring
sand intervals.

•Our results were very encouraging, and
we expect to increase the program to
drill 30 horizontal wells in 2014.

Oxy acreage in blue

29

Fourth Quarter 2013 Earnings - Permian EOR

30

Permian EOR

•Business unit is a combination of
water and CO2 floods.

•$660 mm capital in 2014.

•Symbiotic to manage these assets
together as they have similar development
characteristics and ongoing monitoring
and maintenance requirements.

•The last couple of years we have actually
spent more capital on waterfloods as
we mature the next CO2 developments.

•Efficiency leader in the basin in applying
CO2 flood technology.

•In 2014, 25% of the $660 mm will be
spent on waterflood development and
the remainder on CO2 floods.

•1.4 billion net barrels of reserves and
potential resources remaining to be
developed.

CO2 Pipelines

30

Fourth Quarter 2013 Earnings - Permian Basin

Exploration

31

•Over the last several years the focus of our Permian
exploration program has been to identify unconventional
opportunities, which are then transitioned to full field
development through our evaluation process.

•Our approach has been very successful giving us a large
opportunity set that we are now working to fully develop.

•We continue to see the addition of new plays in the basin
and see years of exploration drilling opportunities ahead
in our 2 million prospective acre position.

31

Fourth Quarter 2013 Earnings - Permian Summary

32

Permian Basin Overall Strategy for Success

1.Maximize field resource potential

•Targeted use of horizontal & vertical drilling, optimizing
development and completion plans, infrastructure investment
to pre-plan for life of field success, successful exploration.

2.Control costs to maximize returns

•Leading technologies and execution efficiencies.

3.Maximize price realizations

•Investing in additionaltake-away capacity, including
completion of the BridgeTex pipeline and build out of our
gathering systems, giving our crude a strategic advantage
to reach either the Houston Ship Channel or Corpus Christi
markets.

32

Fourth Quarter 2013 Earnings - Permian Summary

Significant Position with Key Competitive Advantages

33

ØMore than 2.5 billion BOE in reserves and potential resources
with 15+ years of development and growth opportunities.

ØFlexibility to shift capital among projects and between the two
business units as needed.

ØLarge and diverse portfolio creates a variety of growth options.

ØSignificant infrastructure ownership of storage, gas processing,
gathering lines and pipelines.

ØTakeaway capacity to both Gulf Coast and Cushing secured through
ownership of Centurion and BridgeTex pipelines provides unique
market access for crude oil.

33

Fourth Quarter 2013 Earnings - Permian Summary

Growth Outlook

34

ØSignificant cash flow from Permian EOR to fuel growth.

ØPlan to double drilling rigs over next 3 years to accelerate
development of the Permian Resources unit growth opportunities.

ØExpect to grow Permian Resources production from 64 Mboe/d
in 2013 to 120+ Mboe/d in 2016.

ØCombined with the EOR growth opportunities, we expect to grow
our overall Permian Basin production by a 10% compound annual
growth rate through 2016.

34

Fourth Quarter 2013 Earnings - Permian Summary

Growth Outlook

35

ØSignificant cash flow from Permian EOR to
fuel growth.

ØPlan to double drilling rigs over next 3 years
to accelerate growth in Permian Resources.

211

Production

150

198

57

48

35

Fourth Quarter 2013 Earnings -
California Overview

36

•2013 main goals were to:

−deliver a predictable outcome.

−advance low-risk projects that
contribute to long-term growth .

−reduce the cost structure.

−lower the base decline.

−create a more balanced portfolio.

−test exploration and development
concepts.

•We achieved every one of these
objectives.

36

Fourth Quarter 2013 Earnings - California

37

•2013 Production of 154 mboe/d and free cash flow of ~$1.3 billion
after capital.

•Progressed development of steam floods in Kern Front and Lost Hills,
and started the redevelopment of Huntington Beach Field.

•Improved our capital efficiency by 20% and reduced operating costs
by ~20%.

37

Fourth Quarter 2013 Earnings -
California Capital Program

•Focus on low-decline projects.

•2014 Goals

•Expect this program to deliver
~11% oil production growth,
4% total production growth and
$1.0billion of free cash flow after
capital at current prices.

38

California 2014 Capital - $1.9 bn

•We believe the rate of growth will
further accelerate in 2015+ as
steam and water flood projects
reach full production, base decline
is lowered due to less natural gas
drilling and higher investment in
lower decline oil projects.

38

Fourth Quarter 2013 Earnings -
California Operations - Water Floods

39

Wilmington Field

•Drilled 135 wells and will
increase 7% to 145 wells in
2014.

•Horizontal program was
particularly strong, and
horizontal wells will represent
a greater % of wells in 2014.

Huntington Beach

•Successfully brought online
our two new fit-for-purpose
drilling rigs and drilled and
completed our first two wells
in the project.

•In 2014, we plan to drill 30
wells and will ultimately drill
at least 128 wells.

LA Basin - 2014 Capital of $500 mm

39

Fourth Quarter 2013 Earnings -
California Operations - Steam Floods

Heavy Oil

–Key focus area in 2013 and will
be again in 2014.

–We plan to spend $350 mm
to drill about 420 wells in 2014,
compared to 324 wells in 2013,
to continue the multi-year
development of Kern Front and
Lost Hills steam floods and pilot
new projects.

–Achieved record production in
4Q’13, producing 19 mboe/d,
an increase of 4 mboe/d from
1Q’13.

40

40

Fourth Quarter 2013 Earnings -
California Operations - Elk Hills

•Key objective is to lower the high decline
rate; significant progress toward this goal.

•2014 capital of $600 mm to drill ~325 wells,
an increase of $170 mm over 2013.

•~55% of capital will be targeting shale
reservoirs where capital efficiency efforts
in 2013 had a significant impact.

•Achieved a 23% decline in well costs and
21% decline in operating costs, which
dramatically improved the economics
and increased the opportunity set.

•For example, a typical well that generated
30% IRR prior to our efficiency initiatives
now delivers 50% IRR using the same
product prices.

•In 2014, we will drill ~130 shale wells at
Elk Hills, an increase from 80 in 2013.

•The remaining Elk Hills capital will target
continued development in the shallow oil
zone and Stevens sands.

41

Elk Hills

41

Fourth Quarter 2013 Earnings -
California Operations - Exploration

Exploration

–Solid results for over 5 years.

–The 2014 California program will continue to explore both
unconventional and conventional targets.

–The unconventional program targets several prospects similar
to the 2013 discovery.

–The conventional program will target prospects in and around
our existing production in both the San Joaquin Valley and
Ventura County.

–Extensive proprietary 3D seismic surveys are yielding an exciting
inventory of leads and prospects, which will provide years of
drilling opportunities.

42

42

Production Outlook

154

~160

110

190

44

Fourth Quarter 2013 Earnings -
California Production

43

•Capital shift to lower decline and lower
risk steam and water flood projects.

•We believe we can grow production
from 154 mboe/d to 190 mboe/d in 2016,
a ~7.5% CAGR.

•Water & steam floods will contribute 80%
of production growth.

•90% of growth from projects already online.

•We think this positions California as one
of the lowest risk growth profiles in the
industry.

•Focus on oil production will expand
margins.

•Expect to grow oil volumes by 15%+ CAGR
through 2016.

43

134

138

148

154

139

Fourth Quarter 2013 Earnings -
California Production

44

•Over the long-term, we expect our
California growth prospects to
benefit from changes in our asset
mix.

•Elk Hills and Long Beach, while
having the potential for years of
continued production, have lower
growth prospects due to the mature
state of both of those fields.

•Our water and steam floods, as well
as unconventional opportunities,
should continue to give us double
digit growth for years to come.

Shift in California Production Mix

44

Fourth Quarter 2013 Earnings -
California Production

45

•Share of production from Elk Hills
and Long Beach has declined from
64% in 2009 to 44% in 2013.

•This shift will continue going
forward and the larger share of
higher growth projects with further
accelerate the growth rate in
coming years.

Shift in California Production Mix

92

95

105

110

92

Liquids Production

45

46

Fourth Quarter 2013 Earnings - Appendix

4Q13 & FY2013 FINANCIAL & OPERATING
DATA, VARIANCES & GUIDANCE

46

Fourth Quarter 2013 Earnings - Highlights

•Domestic oil production (Bbl/d)

•Total production (Boe/d)

•Operating costs

•Capital program

•Core earnings

•Core diluted EPS

•2013 CFFO before WC

•YE Cash balance

•2013 Shares repurchased

47

See Significant Items Affecting Earnings in the Investor Relations Supplemental Schedules.

Results

270,000

750,000

Exceeded Target
8% Reduction

Exceeded Target
24% Reduction

$1.4 billion

$1.72

$12.3 billion

$3.4 billion

10.6 million

47

Fourth Quarter 2013 Earnings - Highlights

4Q13-Over-3Q13 Impacts

•Lower oil and gas results

-Lower U.S. oil prices

-Lower NGLs and natural gas
sales volumes

+Higher MENA oil prices

+Higher oil sales volumes

•Lower margins in marketing
and trading, largely due to
commodity price movements

•Lower Chemicals core earnings
due to seasonal trends

48

*See Significant Items Affecting Earnings in the Investor Relations Supplemental Schedules.

Core Diluted EPS*

$1.72

$1.97

$1.83

48

49

4Q13 vs. 3Q13

($ in millions)

Core Results

•2Q13$2.1 B

•3Q132.4 B

•4Q122.3 B

Fourth Quarter 2013 Earnings -
Oil & Gas Segment Earnings

($42)

49

50

Fourth Quarter 2013 Earnings -
Oil and Gas Total Production

750

(6)

(5)

(10)

4

779

Company-wide Oil & Gas Production (mboe/d)

767

Severe winter weather caused significant damage to infrastructure and logistics capability that has
continued to somewhat impact production in January.We expect a return to normal operations with
no effect on production in February.

50

51

(6)

Fourth Quarter 2013 Earnings -
Oil and Gas Domestic Production

475

(3)

476

3

470

Domestic Oil & Gas Production (mboe/d)

51

Fourth Quarter 2013 Earnings -
Oil & Gas Realized Prices

Worldwide

Oil ($/bbl)

Worldwide

NGLs ($/bbl)

Domestic Nat.

Gas ($/mmbtu)

4Q13	$99.27	$44.69	$3.33
WTI %	102%	46%	92%*
Brent %	91%	41%
3Q13	$103.95	$40.53	$3.27
WTI %	98%	38%	90%*
Brent %	95%	37%
4Q12	$96.19	$45.08	$3.09
WTI %	109%	51%	92%*
Brent %	87%	41%

$97.46	$109.35	$3.64
$105.83	$109.71	$3.62
$88.18	$110.08	$3.37

WTI

NYMEX

Price Sensitivity	Pre-tax Income Impact (Quarter)
Oil +/- $1/bbl	=	+/- $38 mm
NGL +/- $1/bbl	=	+/- $8 mm
U.S. Nat Gas +/- $0.50/mmbtu	=	+/- $25 mm

Brent

Realized Prices

Benchmark Prices

52

* As a % of NYMEX

52

53

Fourth Quarter 2013 Earnings -
Oil & Gas Production Costs & Taxes

FY121Q132Q133Q13 4Q13FY13

Domestic$17.43$14.06$14.28$14.65$14.74$14.43

Total$14.99$13.93$13.40$13.60$14.13$13.76

Production Costs ($/boe)

•Taxes other than on income, which are generally related to product prices,
were $2.57 per barrel for FY13, compared with $2.39 per barrel for FY12.

•4Q13 exploration expense was $60 million.We expect 1Q14 exploration
expense to be ~$80 million.

53

54

4Q13 vs. 3Q13

($ in millions)

Guidance

1Q14 expected
to be ~$100 mm

Fourth Quarter 2013 Earnings -
Chemical Segment Core Earnings

Core Results

•4Q13 $ 128 mm

•3Q13181 mm

•4Q12180 mm

54

($ in millions)

Fourth Quarter 2013 Earnings -
Midstream Segment Earnings

Core Results

•4Q13$68 mm

•3Q13$212 mm

•4Q12$75 mm

55

56

Fourth Quarter 2013 Earnings - FY 2013 Cash Flow

FY 2013

($ in millions)

Cash Flow
From
Operations
before
Working
Capital
changes

$12,300

($8,800)

Beginning
Cash $1,600
12/31/12

$3,400

FY’13
Debt / Capital14%

Return on Equity 14%

Return on Capital Employed*12%

* Note: Annualized; See attached GAAP reconciliation.

56

Long-term investment ~ 25% +

Long-term investment ~ 20% +

Americas Oil &Gas

51%

Americas Oil &Gas

53%

57

*Does not reflect any of the effects of our Strategic Review initiatives.

Fourth Quarter Earnings -
Capital Spending 2013 Actual & 2014 Estimate

57

50

Fourth Quarter 2013 Earnings -

2014 Capital Estimate - Domestic Oil & Gas

61

•Domestic Oil & Gas development
capital will be ~49% of our total
capital program.

–Permian rig count to increase
slightly as we swap horizontal
for vertical rigs.

–Total domestic oil and gas capital
is expected to increase ~$800 mm
compared to 2013.

–Permian and CA should each
increase about $400 mm on a
year-over-year basis.

–Midcontinent will remain flat at
around $900 mm.

–Capital will continue to be directed
to oil projects.

58

58

Fourth Quarter 2013 Earnings -
2014 Capital Estimate

International

•Total Al Hosn Gas Project capital should decline ~20% from the 2013
levels, and will make up ~7% of our total capital program for 2014.

•Qatar capital spending is expected to increase ~$200 mm for the
North Dome Phase V development plan.

Exploration

•Should increase ~35% from 2013.

•Focus of the domestic program will be in the Permian basin and CA,
with additional international drilling in Bahrain and Oman.

U.S. Midstream

•Increase ~$200 mm to ~$700 mm for the BridgeTex pipeline project,
scheduled to be operational in the 2H14, and to begin construction of
an LPG export terminal and crude terminal at Ingleside.

Chemicals

•Capital will be ~$500 mm, which includes the Ingleside Ethylene cracker
scheduled to begin construction in 3Q14.

59

59

60

Fourth Quarter 2013 Earnings -
1Q14 & FY 2014 Guidance Summary

Oil & Gas Segment*

•2014 Total Production
of 780 - 790 Mboe/d.

•Domestic FY 2014

−Oil -280 - 295 mboe/d,
~9% increase.

–NGLs - flat.

–Natural gas - modest decline.

•Domestic 1Q14 production flat.

•International FY 2014

–Production volumes:
+5,000 boe/d in 1Q14. flat for
remainder of year; any Al Hosn
production would be incremental.

•Exploration expense: $80 mm in 1Q14.

•Production Costs: ~$14 / boe for FY 2014.

•DD&A: ~$17.40 for FY 2014

Price Sensitivity	Pre-tax Income Impact (Quarter)
Oil +/- $1/bbl	=	+/- $38 mm
NGL +/- $1/bbl	=	+/- $8 mm
U.S. Nat Gas +/- $0.50/mmbtu	=	+/- $25 mm

Chemical Segment

•~$100 mm pre-tax income in 1Q14.

Corporate

•Capital Spending: ~$10.2 billion.

•Income tax rate: 40% - 41%.

* Does not reflect any of the effects of our Strategic Review initiatives.

60

Fourth Quarter 2013 Earnings Conference Call

Q&A

61

Occidental Petroleum Corporation
Return on Capital Employed (ROCE)
For the Twelve Months Ended December 31,
Reconciliation to Generally Accepted Accounting Principles (GAAP)
	2012		2013
RETURN ON CAPITAL EMPLOYED (%)	10.3%		12.2%
GAAP measure - net income	4,598		5,903
Interest expense	117		110
Tax effect of interest expense	(41	)	(39	)
Earnings before tax-effected interest expense	4,674		5,974
GAAP stockholders' equity	40,048		43,372
Debt	7,623		6,939
Total capital employed	47,671		50,311

EX-99.5

    ex99_5-20140130.htm