First Quarter 2017 EarningsConference CallOccidental Petroleum CorporationMay 4, 2017

2

Forward-Looking StatementsPortions of this presentation 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; not successfully completing, or any material delay of, field developments, expansion projects, capital expenditures, efficiency projects, acquisitions or dispositions; uncertainties about the estimated quantities of oil and natural gas reserves; 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 or regulations; reorganization or restructuring of Occidental's operations; 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 presentation. 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 I, Item 1A “Risk Factors” of the 2016 Form 10-K.

Use of non-GAAP Financial InformationThis presentation includes non-GAAP financial measures. You can find the reconciliations to comparable GAAP financial measures on the “Investors” section of our website.

Cautionary Statements

3* Cash Flow Breakeven after Dividend and Growth Capital

Opening Remarks

• Returns-focused portfolio optimization

• Differentiated value-based approach

• Pathway to cash flow breakeven*

4

2013Actual

Cali-fornia

2013 Excl.California

OtherUS

MENA 2013Adjusted

PermianRes.

Al Hosn OtherInternational

South Texas 2016Ongoing

High-MarginProduction

Growth Goal

Cash FlowBreakeven

at $50 WTI*

Divested assets that did not generate competitive corporate returns or free cash flow

Invested in assets with highest cash margin and capital efficiency while limiting capital to low-return assets. Drove decision to divest natural gas in South Texas.

Investing in assets with higher cash margin and lower capital intensity Lower relative returns drove decision to divest of South Texas Gas propertiesProceeds to be re-deployed in Permian Resources

Prod

uctio

n (M

boed

))

South Texas Gas propertiesDecline since 2013: 17 Mboed2016 Production: 27 Mboed (11% oil production)

763 (154)

609 (62)(79)

46859

64 28 (44)575

80 655

Set to generate both returns to shareholders and value-based growth

* Cash Flow Breakeven after Dividend and Growth Capital

Multi-year Returns Focused Portfolio Optimization

5

• ~9 Mboed replaces South Texas Gas properties’ operating cash flows.

• We expect to reach this replacement volume by early 2018.

Divestiture Proceeds to be Reinvested into Higher-Margin Permian Resources

DevelopmentCost

Opex G&A ProductionTaxes

Cash Costs

$16 - $19 / boe

Permian Resources Cost Structure

Note: Estimated future project costs.

6

Differentiated Value-Based Approach

• More Oil

• Less Cost

• Better Inventory

Creating shareholder value over the long-term

• Culture of innovative technology and process– Subsurface characterization– Integrated development planning– Oxy Drilling Dynamics– Innovative facility designs – Long-term base management– Enhanced reservoir recovery

• Early adoption of external trends– Big data, analytics, and mobile workforce– Multi-lateral wells (SL2)– Crude export facility

• Innovative cost efficiency strategies– Logistic and Maintenance hubs – OBO portfolio and investments

7

1. Base/Maintenance Capital

2. Dividends

3. Growth Capital

4. Acquisitions

5. Share Repurchases

Subject to Returns and Market Conditions

Cash Flow Priorities

8

Pathway:> Grow high margin production with low

capital intensity

> Continue to invest in low decline, free cash flow businesses at low cost

> Accelerate cash flows from the tail of the portfolio to fund production growth

> Advance value-based development approach with technology

Executing a plan to fund a growing dividend and 5% – 8% growth at $50 WTI.

Pathway to Cashflow Breakeven

Milestones:> 80 Mboed of production growth

> Ample options to self-fund growth

• ~$2.2Bn = South Texas, tax refund, PAGP

• +“Win-win” Trades, Partnerships, Sales

Accelerators:> Improving conditions in Midstream and

Chemicals and commodity prices

9

Occidental Petroleum

• Financial Highlights

• Differentiated Development

• Guidance

10

Total company production (boed)

Total Permian Resources production (boed)

Permian Resources oil production (bod)

Reported and Core diluted EPS

1Q17 CFFO before Working Capital & Other

1Q17 Capital Expenditures

Cash balance @ 3/31/2017

*See Significant Items Affecting Earnings in the Earnings Release Attachments.

Results584,000

129,000

78,000+7% QoQ

$0.15

$1.1 billion

$750 million

$1.5 billion

First Quarter 2017 Core Results

11

Beginning Cash Balance1/1/17

CFFO Before WorkingCapital

Change in WorkingCapital

Capital Expenditures Dividends Ending Cash Balance3/31/17

YTD 2017 Cash Flow and Cash Balance Reconciliation

$1.5

($0.6)

$1.1

$2.2

($0.8)

($0.4)($ in billions)

1212

Occidental Petroleum

• Financial Highlights

• Differentiated Development

• Guidance

13

Successful Start-up of InglesideEthylene Cracker

• On time and on budget

• Not a merchant plant

• JV structure and supply agreements with Mexichem ensures returns above cost of capital for both parties

• Differentiated Value based approach

14

Market Overview

• Major industry consolidation complete

• Caustic soda supply-demand balance continues to improve

• PVC demand improved YoY

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50

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E

$ M

illio

ns

Chemicals Pre-Tax Earnings (EBIT)1

0.00

1.00

2.00

3.00

4.00

5.00

0

100

200

300

400

500

1Q

12

2Q

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$/m

cf

$/D

ry S

hort

Ton

FO

B U

S G

ulf C

oast

Chemicals Profitability DriversCaustic Soda Price Natural Gas Price Price

Notes: 1 Chemicals pre-tax earnings excluding special items. 2 IHS Domestic Average Spot Caustic Soda Price. 3 Factset natural gas prices.

2 3

15

Domestic O&G

• Maximize value of portfolio

• Differentiated value-based approach

• Innovative technology

16

Maximize Value of Portfolio - Low Capital Intensity Drives Value

*Includes estimated net non-operated rigs**Calculated using estimated total year capex (drilling, completions, hookup, facilities, infrastructure, capital workovers, maintenance, seismic). Annual wedge represents the new production added in each year from the capital program (excludes base production).

0

2

4

6

8

10

12

14

16

18

20

-

50

100

150

200

250

300

2017 2018 2019

Prod

uctio

n (M

boed

)

Multi-Year Permian Resources Growth

Rig

Cou

nt

20% CAGR

30% CAGR

Base rig count* Upside rig count*

6

8

9 9

1415 Annual Wedge

STX SaleRe-invested11 – 13 rigs

at exit

< $30MM$ per Mboed**

2015 / 2016 $54 MM

2017 $33 MM

2018 $29 MM

2019 $23 MM

+ 400 wellsTo be added

< $50 BE in 2017

Current < $50 BE = 2,500

Landing ZonesFlow Unit + StimulationMulti-flow unit modular developmentFacilities UtilizationTechnology and OBO operations

More Oil

Less Cost

Better Inventory

Sustainable throughTop Tier Inventory

2017 Exit rig count*

All-In Capital Intensity

17

0

50

100

150

200

250

300

0 30 60 90 120 150 180

Cum

ulat

ive

Mbo

e4

,50

0 ft

Late

rals

Days Online

Value Based Development Increases ReturnsGreater Sand Dunes

Current* Wolfcamp XY

Old 2nd Bone Spring Design -2014

Three high-return development benches• Currently three play leading benches under development

> Modular development

> Area appraisal continues to add new benches / flow-units

• Longer laterals

• Reducing secondary bench breakeven prices by ~$10

> Facilities saves ~$800k per well

> SL2 saves >$500k per well

> OPEX reduction up to 50%

Current* 2nd Bone Spring

Moving to longer laterals to improve returns

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2016 1H2017 2H2017 2018

Late

ral L

engt

h (F

t)

Current* 3rd Bone Spring

*Current represents wells online 3Q16 – 1Q17

18

-

25

50

75

100

125

150

0 30 60 90 120 150 180

Cum

ulat

ive

Mbo

e

Days on Production

Greater Barilla Draw• Red Bull South Active and

Improving

> 2 rigs currently operating

> 3 wells drilled and 3 wells online since acquisition date

> Record Peak 24hr WC B 7,500ft at 1,954 boed

> 23% lower completion costs

> Updating plan from 7,500ft to 10,000ft laterals

• Currently 3 rigs in Greater Barilla Draw> 2 additional rigs in 2Q17

Wolfcamp B Improvement = frac optimization to drive results

Efficient stimulation without sacrificing production

$11.6

$9.7$8.5

$0

$2

$4

$6

$8

$10

$12

Prior Operator Oxy Current Oxy Potential

$M

M

Drilling Cost Completion Hookup

Wolfcamp B 7,500ft Well Costs

Value Based Development Increases Returns

Oxy WC B 7,500ft Fracs

Prior Operator WC B 7,500ft Fracs

19

-

25

50

75

100

125

150

175

0 30 60 90 120 150 180 210 240 270 300 330 360

Cum

ulat

ive

Oil

-Mbo

Days on Production

Old WC B Design

New WC B Design

All WC A Wells

Midland Basin - Merchant

• Currently two play leading benches under development

> Landing point optimized flow units

> Wolfcamp B performance +42%

> Oil cut from 61% to 77%+

• 2017 lateral length ~ 8,700ft

• Two benches now < $40 BE> Pad D&C saves ~$900k per well

$11.6

$6.3$5.2 $5.1

$4.5

$-

$2

$4

$6

$8

$10

$12

2014 2015 2016 2017 Best

$M

M

Drilling Completion Hookup

Wolfcamp A & B 7,500ft Well Costs

Wolfcamp B Improvement = two high return development benches

Continuous well cost improvement yielding high returns

Value Based Development Increases Returns

20

SL2 Potentially Lowers Secondary Bench BE by $5:

> Lowers well cost by $0.5 - $1.0MM

> Reduces operating costs by over 50%

> Sequencing increases facilities utilization

> One artificial lift system saves $0.2MM per lateral

Project Timeline:

> Project chartered in 2015, design and lab test in 2016

> First installation completed in December 2016

> Barilla Draw - Betty Lou 1016H, WCA & 2nd BS

> 2017+ wells designed for future SL2 capability

Single Location Sequenced Lateral (SL2) Lower CostsSL2

21

Logistic & Maintenance Hub Underway

• Secures supply availability

• $500 – $750k savings per well> Below market cost of supply will offset

potential service cost inflation

> Reduces last mile logistics costs

• Mutually beneficial partnerships

Service company yard• Maintenance• Stimulation & Cement• Service directional tools

Sand Transload and Storage• 6 Silos• 3 Unit train loops• Transload capacity

OCTG Laydown Yard• ~20 railcar spots• Dedicated truck entry/exit• Staging, returns, reclamation

OxyChem Acid Facility• Transload, storage, and

dilution of HCI for fracs• ~20 rail transload capacity

• Strategically located in New Mexico

• 244 acres• 3 unit train loop• 30,000 tons of sand storage• Supports 10-12 rigs/year• Operational in early 2018

Value Chain Partnerships Lower Costs

2222

Occidental Petroleum

• Financial Highlights

• Differentiated Development

• Guidance

23

Oil & Gas Segment • FY 2017E Total Production

> 595,000 – 615,000 boed

> Permian Resources production of 140,000 – 150,000 boed

• 2Q17E Production

> Total production of 580,000 – 595,000 boed

> Permian EOR production flat

> Permian Resources production of 135,000 – 140,000 boed

> Modest impact of OPEC quota constraints and volume effects under PSC contracts due to higher oil prices.

Production Costs – FY 2017E

• Domestic Oil & Gas: ~$14.00 / boe

Exploration Expense

• ~$30 MM in 2Q17E

DD&A – FY 2017E

• Oil & Gas: ~$15.00 / boe• Chemicals and Midstream: $685 MM

Midstream

• $5 – $15 MM pre-tax income in 2Q17E

Chemical Segment

• ~$200 MM pre-tax income in 2Q17E

Corporate

• FY 2017E Domestic tax rate: 36% • FY 2017E Int'l tax rate: 55%• Interest expense of $85 MM in 2Q17E

2Q17 and FY 2017 Guidance Summary

24

75

110

124 129

135 - 140140 - 150

2014 2015 2016 1Q17 2Q17E 2017E

Oil NGL Gas• Total production grew 5% from Q4 16 to 129 Mboed> Oil production up 7% from Q4 16 to 78 Mbod

• Increased activity in 1Q 2017> Exited Q1 with 7 rigs> 21 wells online in 1Q17 vs. 16 in 4Q16> Added 5 top tier performing wells in Greater Sand Dunes

• 2017 program: increase in activity expected in 2Q17> 2 rigs to be added in Q2 in Greater Barilla Draw Area> Expect to drill 28 wells and put online 26 wells in 2Q17

• 2017 program: expect 120+ operated wells online> Increased activity will be focused in Greater Sand Dunes

and Greater Barilla Draw.

Permian Resources Results and Guidance

Appendix

26

6076

584

1 (30)

4Q16 Permian Other Domestic International 1Q17Com

pany

-wid

e O

il &

Gas

Pr

oduc

tion

(Mbo

ed)

Dom

estic

Oil

& G

as

Prod

uctio

n (M

boed

)

296

8 (1) 0 303

4Q16 Oil NGLs Natural Gas 1Q17

Inte

rnat

iona

l Oil

& G

as

Prod

uctio

n (M

boed

)

311 (12)(6)

(12)281

4Q16 Oil NGLs Natural Gas 1Q17

Oil and Gas Production Results

27

WorldwideOil ($/bbl)

WorldwideNGLs ($/bbl)

Domestic Nat.Gas ($/mmbtu) WTI NYMEXBrent

Realized Prices Benchmark Prices

1Q17 49.04 21.59 2.68 51.91 54.66 3.26

WTI % 94% 42% 82%*

Brent % 90% 39%

4Q16 45.08 18.36 2.39 49.29 51.13 2.95WTI % 91% 37% 81%*Brent % 88% 36%

1Q16 29.42 10.86 1.50 33.45 35.08 2.07

WTI % 88% 32% 73%*Brent % 84% 31%

* As a % of NYMEX

Oil and Gas Realized Prices

28

Permian Resources 2017 Focused Development

• Contiguous Acreage

• Multi-bench

• Capable Infrastructure

• Valuable Growth Greater Barilla Draw – 5,000+ Locations

Greater Sand Dunes – 2,000+ Locations

Permian Resources Acreage Permian EOR Acreage

NM Delaware Basin

TX Delaware Basin

Midland Basin

Central BasinPlatform

New Mexico NW Shelf

29

Permian Resources Inventory 4Q16

• Added 1,250 locations BE < $50

• Added 3,150 total locations

• Increased average length from 5,950ft to 7,100ft

• Traded 10,000 net acres to enable longer lateral and consolidated facilities

• 14 years of inventory <$50 breakeven at a 10 rig development pace

0

2,000

4,000

6,000

8,000

10,000

12,000

BE <$50 BE<$60 BE <$70 AdditionalInventory

Total

~5,300

2015 Locations8,500

~11,650~11,650

~2,500

~4,100

2016 Added3,150

Texas Delaware Basin

Midland Basin

New Mexico Delaware Basin

Increased Total Horizontal Drilling Locations ~37%

Note: Breakeven values based on NPV10.

Locations within 300,000 of 650,000 net acres in Basin Development Areas

Growing and Improving Inventory

• Improving well performance

• Delineation of total acreage 

• Development area cost synergies

30

Target FormationRecent Well Results

Well Name Lateral Length (ft)

Peak 24 Hr(boed)

Peak 30 Day (boed) Oil (%)

Brushy Canyon Federal 23 13H 4,376 899 833 90%

Avalon James 29 38H 4,730 1,132 1,115 79%

1st BSS Evaluating

2nd BSS

Cedar Canyon 22 5H 4,468 3,292 2,711 80%

Cedar Canyon 29 2H 4,584 2,782 2,370 81%

Cedar Canyon 28 8H 4,536 2,700 2,385 81%

Oxy 1Q17 Average 5,081 2,214 1,944 81%

3rd BSSCedar Canyon 22-15 31H 5,868 2,236 1,893 74%

Cedar Canyon 22-15 32H 5,868 2,231 1,852 75%

Wolfcamp XYPatton 18 6H 4,401 2,774 2,150 71%

Cedar Canyon 16 33H 4,418 2,397 2,049 71%

Cedar Canyon 16 34H 4,235 2,287 1,967 70%

Wolfcamp AJanie Conner 204H 4,500 1,980 1,221 78%

B Banker 226H 4,400 1,874 1,030 76%

Janie Conner 207H 4,500 1,272 1,121 72%

Wolfcamp DJanie Conner 221H 4,522 2,282 1,809 39%

Tiger 14 24S 28E 224H 4,376 1,719 1,417 47%

Note: Wells included in table include non‐operated wells.  Production data is from internal system for operated wells and from operator data and IHS Enerdeq for non‐op wells where available.Wells in blue font were turned to production in 1Q 17.

Barilla Draw Type LogGreater Sand Dunes

Proven Economic Delineating

Outstanding Results in Greater Sand Dunes Area Multi‐Bench Development

Brushy Canyon

Avalon

1st Bone Spring

2nd Bone Spring

3rd Bone Spring

Wolfcamp X‐YWolfcamp A

Wolfcamp D

6,00

0 ft

New

New

31

Target Formation

Recent Well Results

Well Name Lateral Length (ft)

Peak 24 Hr(boed)

Peak 30 Day (boed)

Oil (%)

Avalon Evaluating

1st Bone Spring Evaluating

2nd Bone Spring

Roan State 24 #51HAardvark State 6 2H

4,5144,947

9931,254

762821

83%87%

3rd Bone Spring Big George 180 SW 3H 7,576 759 571 57%

Wolfcamp A

Buzzard State Unit #16HPeck State 258 #6H

Buzzard State Unit #15HLenox 2 #5H

Eagle State 28 #13H

7,7004,2127,5984,7214,250

2,0502,2442,0192,4251,958

1,8221,7911,7641,5061,505

74%82%73%71%69%

Wolfcamp DFOppenheimer 188 1H

Nyala Unit 9B #3HOppenheimer 188 2H

Teller 186 1H

4,5006,5754,7764,681

2,4511,5351,5471,707

1,9071,2471,3401,263

82%83%82%81%

Wolfcamp B

Manhattan 183W 1HDaytona Unit 1B 2H

Black Bear State 11 NE #3H

Iron Mike 40 SE 2H

7,0446,9476,935

7,376

1,9541,8971,215

1,703

1,58415441,124

1,416

75%79%85%

76%

Wolfcamp C Lemur 24 1H 4,251 1,125 937 81%

Note: Wells included in table include non‐operated wells.  Production data is from internal system for operated wells and from operator data and IHS Enerdeq for non‐op wells where available.  Well highlighted in blue is most recent well put online by Oxy from newly acquired acquisition area.

Barilla Draw Type LogGreater Barilla Draw – Drilled 228 Wells Across 8 Benches

Proven Economic Delineating

Improving Results in Greater Barilla Draw Area Multi‐Bench Development

Avalon

1st Bone Spring

2nd Bone Spring

3rd Bone Spring

Wolfcamp AWolfcamp DF

Wolfcamp C

4,50

0 ft

Wolfcamp BNew Red bull South

32

Permian Resources Non-OperatedAssets

• Significant OBO position delivers ~13% of domestic production

• Leveraged to deliver high returns, knowledge, and transaction opportunities

• Well participation provides data that progresses delineation efforts across Oxy’soperated assets

2015+ Non‐Operated Activity

Delaware 4San Andres 7

Yeso 13Bone Spring 70Spraberry 5Wolfcamp 143Other 15

Total 257

Target 2015+ Wells

TX Delaware Basin

Central BasinPlatform

Midland Basin

New Mexico NW Shelf

NM DelawareBasin

Greater Sand Dunes

Greater Barilla Draw

Permian Basin Acreage