August 3, 2017Occidental Petroleum Corporation

Second Quarter 2017Earnings Conference Call

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

Occidental Petroleum

• Pathway to Breakeven Progress

• Financial Summary and Guidance

• Permian Highlights

• Closing Remarks

4

Occidental Petroleum Pathway to Breakeven and 2Q17 Highlights

> Initiated integration and improvement plan for EOR Seminole-San Andres Unit

> Captured caustic soda price increases in Chemicals segment

> Record quarterly production at Al Hosn Gas Plant

> Exported 225 Mboed from Ingleside Oil Terminal

Operations and Technological Progress

Value-based Development ApproachPortfolio Management

> $2.2 Bn 2Q17 cash balance, including South Texas sale proceeds and tax refund

> Traded 7,000 net acres YTD to enable longer laterals and consolidated facilities

> 2Q17 Resources to EOR Permian Transactions

• +$80 MM CFFO in 2019*

*Assumes $50 WTI; $70 MM CFFO at $40 WTI

> Permian Resources increases production 9 Mboed sequentially

• 400 locations added at breakeven below $50 WTI

• Added 3 MM feet of horizontal lateral footage to inventory

• Increased average lateral length in inventory from 7,100’ to 7,500’

• Record IP30 Texas Delaware wells

• Play-leading well performance in New Mexico

>Raised quarterly dividend for 15th consecutive year from $0.76 to $0.77 per share

5

0.0

1.0

2.0

3.0

4.0

5.0

6.0

2Q17 CFFOAdjusted to

$40 WTI

Chemicals Midstream &Marketing

71 MboedPermian

ResourcesProduction

OtherImprovements

Cash FlowNeutral at $40

WTI

Increase inCash Flow at

$50 WTI

Cash FlowBreakeven with5%-8% Growth

at $50 WTI

$3.3 $3.5 $3.7$4.3 $4.5

Current Dividend

$2.4

Sustaining Capital$2.3

$120 MM per $1 Change in WTI

Current Dividend

$2.4

Sustaining Capital$2.1

Cash Flow Breakeven at $50:Dividend + 5% – 8% Production Growth $5.7 $5.7

Ope

ratin

g Ca

sh F

low

($ B

n) Growth Capital$1.0

Cash Flow Neutral at $40:Dividend with Flat Production

Seminole-San Andres Acquisition + Chemicals

Pathway to Cash Flow Breakeven at Low Oil Prices

$4.5

6

$0.2$0.2

$0.3

$0.7

0.0

0.2

0.4

0.6

0.8

Category 1 Category 2 Category 3 Category 4Chemicals Midstream Permian Resources Production

Achieving Goals to Cash Flow Neutrality at $40

Ethylene cracker achieved full quarter of operating income with first cash distribution expected in 3Q17

Marketing differential improved substantially

Added 9 Mboed of high-margin Permian Resources production

Chemicals market fundamentally improving

Announced cash-neutral Permian transactions

Other Improvements

Annualized Cash Flow From Operations Improvements ($ Bn)Breakeven PlanAchieved since 1Q17

SSAUAcquisition

Chemicals

7

Ample Liquidity to Fulfill Plan Even at $40 WTI

Cash flow outspend through the completion of our plan is covered by available liquidity, including:

• Current cash balance: $2.2 Bn

• Portfolio management: $0.5 - $2.0 Bn

• PAGP units: $0.8 Bn

• Undrawn revolving credit facility: $2.0 Bn

We do not anticipate increasing debt levels to achieve plan

Cash Flows Through End of 2018 at $40 WTI

Operating Cash Flow

$B

n

6.0

5.0

4.0

3.0

2.0

1.0

0.0

(1.0)

(2.0)

(3.0)

(4.0)

Remaining 2017

2018

Dividend Payments

Capital Program

Cash Flow Deficit

Available Liquidity

Cash Balance

PAGP

Portfolio Management

$3.6 -$3.9 Bn

8

Occidental Petroleum

• Pathway to Breakeven Update

• Financial Summary and Guidance

• Permian Highlights

• Closing Remarks

9

Total reported production (boed)

Total ongoing company production (boed)

Total Permian Resources production (boed)

Core diluted EPS*

2Q17 CFFO before Working Capital & Other

2Q17 Capital Expenditures

Cash balance as of 6/30/2017

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

Results601,000

594,000

138,000

$0.15

$1.0 Bn

$0.8 Bn

$2.2 Bn

2Q 2017 Core Results

10

Beginning CashBalance1/1/17

CFFO BeforeWorking Capital

Change inWorking Capital

CapitalExpenditures

Dividends Asset Sales Acquisitions/Other

Tax Refund Ending CashBalance6/30/17

YTD 2017 Cash Flow and Cash Balance Reconciliation

$2.2($1.2)

$2.1

$2.2

($1.5)($0.4)

($ in Bn)

$0.6$0.8

($0.4)

11

Oil & Gas Segment • FY 2017E Total Production

> 597,000 – 605,000 boed

> Permian Resources production of 140,000 – 147,000 boed

• 3Q17E Production

> Total production of 600,000 – 610,000 boed

> Permian EOR production 150,000 – 153,000 boed adjusted for 2 months of acquisition volumes

> Permian Resources production of 138,000 – 143,000 boed adjusted for 2 months of divested volumes

Production Costs – FY 2017E

• Domestic Oil & Gas: ~$14 / boe

Exploration Expense

• ~$40 MM in 3Q17E

DD&A – FY 2017E

• Oil & Gas: ~$15 / boe• Chemicals and Midstream: $685 MM

Midstream

• $30 – $50 MM pre-tax income in 3Q17E

Chemical Segment

• ~$230 MM pre-tax income in 3Q17E

Corporate

• FY 2017E Domestic tax rate: 36% • FY 2017E Int'l tax rate: 55%• Interest expense of $85 MM in 3Q17E

3Q17 and FY 2017 Guidance Summary

12

Occidental Petroleum

• Pathway to Breakeven Update

• Financial Summary and Guidance

• Permian Highlights

• Closing Remarks

13

Seminole-San Andres Further Strengthens Our Leading Position in EOR

*Source: 2014 Oil & Gas Journal, EOR Survey, adjusted for recent Oxy EOR acquisition

Occidental

Kinder Morgan

DenburyChevron

Exxon Anadarko

Whiting Resolute

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 5 10 15 20 25 30 35 40

Inje

ctio

n W

ells

CO2 Projects

Gas EOR Projects*

$0$100$200$300$400$500$600$700

Base Case Target Upside Case

Value of Operating Cost Synergies ($MM PV10)

$5/Boe

$7/Boe

$10/Boe

• Seminole-San Andres is now our largest operated CO2project in the Permian

> San Andres reservoir is world-class

> Oxy now operates 34 CO2 projects in the Permian Basin

• Scale in the Permian provides operating cost savings and production reliability opportunities:

> Base case savings ($5/Boe): improved well maintenance, automation, and commercial scale for supply chain and logistics

> Target savings ($7/Boe): improved plant reliability

> Upside savings ($10/Boe): asset performance at parity with our Denver Unit

• Additional opportunities: D&C cost improvement, plant expansion to accelerate growth, and re-drill and ROZ potential

Production Volumes

14

0

500

1,000

1,500

2,000

Proven Leader in Maximizing Recovery Across the Permian

<$10 <$6

Permian EOR Net Resource Potential

MM

BO

E

CO2 Floods

TZ/ROZ*

Water Floods + Other Infill Drilling

Opportunities

High-gradable Inventory

*Transition Zone and Residual Oil Zone

Permian EOR

• Seminole San Andres Unit adds low F&D inventory> ~100 MMboe at < $6.00

future development cost

• Significant opportunity to improve and grow new inventory> Subsurface characterization

> Operating efficiency

> Technology

Future Development Cost ($/BOE)

Permian EOR Water Floods

Midland Basin

Central BasinPlatform

Additional Conventional

Inventory

SSAU Acquisition

Permian EOR CO2 Floods

Permian EOR Plants

SSAU

Total Identified

Barrels

15

0

500

1,000

1,500

2,000

2,500

3,000

4Q16 <$50 BE Drilled 1H17 DemonstratedCapex

Efficiency

DemonstratedWell Performance

LandImprovement

EvaluatedNew Acreage

2Q17 <$50 BE

Added 400 Hz Locations <$50 BreakevenReached <$50 inventory additions goal since 4Q16

• + 400 locations YTD

• + 3.5 MM feet of total horizontal lateral

• Increased <$50 average length from 8,400’ to 8,600’

• Cost and well performance improvements are sustainable

• Executed 7,000 net acres of trades to enable longer laterals

• Evaluated ~15,000 net acres of new development areas

2,500

2,855

16 years of inventory <$50 breakeven with 10 rigs

Midland Basin

Texas Delaware

Basin

New Mexico

Delaware Basin

Breakeven defined as positive NPV 10

Und

evel

oped

Dril

ling

Loca

tions 45

155 45100

100

16

2015 & 2016Avg

2017 FacilitesReduction

SubsurfaceEngineering

LongerLaterals

2018 2019

*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)** Other capex includes seismic, science, and maintenance capex.

Permian Resources Capital Intensity Improves through 2019

All-In Capital IntensityAnnual Capex $MM / Annual Wedge Mboed*

$54MM

$33MM

2018 & 2019$27MM – $23MM

• 2017 to 2019 – Value-based Development reduces capital intensity> Facilities, infrastructure and other** 23% to <15%

of capital budget> New Mexico wells ~30% to ~55% of total well count> Effective lateral length from 7,700 ft to 8,600 ft for

wells drilled

• Future intensity improvement opportunities> Well productivity > Additional capital efficiency > SL2 in secondary benches> Maintenance & logistics hub> Water recycling

10% improvement in well productivity or capital costs reduces capital intensity by $2MM

$42MM

2H 2017 Rig Ramp

Subsurface Characterization

17

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% 3-yr CAGR

30% 3-yr CAGR

Base rig count* Upside rig count*

6

8

8 8

1314

STX SaleRe-invested

13 rigs at exit

2017 Exit rig count*

Current trajectory of 30% CAGR

• Exited 2Q with 11 operated rigs> 26 wells online in 2Q17

• Exit 2017 with 11 company operated rigs, 2 net non-op rigs> Avg lateral length 7,400 in 1H17 to 7,900

in 2H17

> 2017 wells online ~130

• Shifting activity to New Mexico> 5 NM rigs in 2H 2017

> 7+ NM rigs in 2018+

> 1 net non-op rig in 2018+

Achieving Plan Through Value-based Approach

*Includes estimated net non-operated rigs

18

Occidental Petroleum

• Pathway to Breakeven Update

• Financial Summary and Guidance

• Permian Highlights

• Closing Remarks

Appendix

20

Appendix Contents

• Permian Updates

• Social Responsibility, Environment, and Governance

• Journey to Digital Transformation

• Company Overview and Value Proposition

21

Permian Resources Wells Continue to Improve

Top Peers is average of Peers in the Top 15 based on # of wells online in 2016 with 6 month cumulative production available.Oxy and Peer data sourced from IHS Performance Evaluator, Gas Equivalent calculated at 20:1, solid bars represent oil, grey bars represent gas

New Mexico Bone Spring

New Mexico Wolfcamp

Texas Delaware Wolfcamp

Midland Basin Wolfcamp

AVG Lat Length (ft) 4,169 4,937 5,174 ~6,000 4,849

AVG Lat Length (ft) 4,576 ~6,700 5,158 AVG Lat Length (ft) 6,700 7,457 7,467 ~8,200 7,907

AVG Lat Length (ft) 4,807 5,418 ~7,500 5,938

*Operators Include: Bopco, Bta Oil Producers, CVX, CXO, DVN, EOG, Fasken Oil And Ranch, GMT, LGCY, Mewbourne, MTDR, Regeneration Energy, WPX, XEC, XOM

*Operators Include: APA, APC, BHP, CDEV, CXO, EOG, FANG, HK, Mewbourne, MTDR, RDSA, REN, RSPP, WPX, XEC

*Operators Include: APA, CVX, CXO, ECA, EGN, END, EPE, FANG, LPI, PE, Permian Rscs, PXD, RSPP, SM, XOM

*Operators Include: Bc Opg, COP, CXO, DVN, EOG, Mewbourne, MTDR, WPX

0

50

100

150

200

2015 1H16 2H16 2017Target

Top Peers2016

0

50

100

150

200

250

2015 1H16 2H16 2017Target

Top Peers2016

0

50

100

150

2015 1H16 2H16 2017Target

Top Peers2016

020406080

100120

2015 1H16 2H16 2017Target

Top Peers2016

6 M

onth

BO

E Cu

mul

ativ

e Pr

oduc

tion

6 M

onth

BO

E Cu

mul

ativ

e Pr

oduc

tion

6 M

onth

BO

E Cu

mul

ativ

e Pr

oduc

tion

6 M

onth

BO

E Cu

mul

ativ

e Pr

oduc

tion

22

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Breakeven <$50

Breakeven <$60

Breakeven <$70

AdditionalInventory

2Q17 Normalizedto 7,100'

4Q16

Added ~20 Rig Years of Activity to <$50 Inventory

2,855

4,250

5,725

11,325 11,650

Permian Resources Inventory 2Q17

• + 400 locations BE <$50

> ~300 in New Mexico

> Replaced inventory from divestitures

• + 3.0 MM ft of horizontal lateral footage to inventory

> Increased average length from 7,100 ft to 7,500 ft

Midland Basin

Texas Delaware

Basin

New Mexico Delaware

Basin

*2Q 2017 increased lateral length adjustment to normalize current inventory to 7,100’. **Breakeven defined as positive NPV 10

11,963*

Und

evel

oped

Dril

ling

Loca

tions

23

Permian Resources• Significant acreage & growth

potential in all development areas

• ~637,000 net acres within the Delaware and Midland Basin boundaries

• NM Delaware Basin 290,000

• TX Delaware Basin** 150,000

• Midland Basin* * 210,000

Total ~650,000

NetAcres*

Resources Basin Development Areas

• Central Basin Platform 215,000

• New Mexico NW Shelf 150,000

• Emerging Unconventional 50,000

• Continuing Evaluation 335,000

Total ~750,000

NetAcres*

Other Resources Unconventional Areas

• Resources – Unconventional Areas 1.4• Enhanced Oil Recovery Areas 1.1

Oxy Permian Total ~2.5MM

NetAcres*

Business Area Acreage

Permian Resources Acreage Permian EOR Acreage

NM Delaware Basin

TX Delaware Basin

Midland Basin

Central BasinPlatform

New Mexico NW Shelf

*Includes surface and minerals.**Adjustment for transactions of 13,000 net acres announced 6/19/2017 where Oxy divested non-strategic acreage in Andrews, Martin and Pecos Counties and added incremental acreage in a new development area in Glasscock County.

2Q Permian Resources Transactions** (13,000)

Updated Resources Basin Acreage ~637,000

• ~302,000 net acres associated with 11,325 wells in unconventional development inventory

• Divested acres offset with additional acres evaluated in 1H17

24

0

50

100

150

200

250

0 30 60 90 120 150 180

Cum

ulat

ive

MB

OE

4,5

00

ft L

ater

als

Days Online

Value-Based Development Increases ReturnsGreater Sand Dunes

Current* Wolfcamp XY

Old 2nd Bone Spring Design -2014

Three high-return development benches

Current* 2nd Bone Spring

High-margin growth barrels

Current* 3rd Bone Spring

*Current represents wells online 2016 and 2017

• Operating Excellence

> Oxy operated OPEX ~$5.50/boe in Greater Sand Dunes development

• Continued play-leading results from three benches

> Increasing activity in 2H 2017

> Significant production growth expected in Q4

• Longer laterals

> More than 50% of wells in 2H17 are 7,500 and 10,000ft laterals

NM Oxy Operated Production NM Oxy Operated Opex

$-

$4

$8

$12

$16

2014 2017 YTD

Ope

x /

BO

E ($

)

-

10

20

30

40

50

60

2014 2017 Q2 2017 Est. Exit

Net

MB

OEP

D

Legacy Growth

25

-

20

40

60

80

100

120

140

160

180

200

- 30 60 90 120 150 180Cu

m M

BO

E Days Online

Greater Barilla Draw

New Records and Focused Activity 2017 Barilla Draw proper– Wolfcamp A Optimized Landing Point Results

Value-Based Development Increases Returns

Lyda 16H– 10,164’

Pre-2017 Wolfcamp A WellsAvg. Lateral ~4,700’

• Cumulative oil production reached 100 MBO in only 42 days, a record for Oxy in the Permian (100 MBOE reached on day 35).

Toyah 11H – 9,845’

Allen 11H – 4,971’ Allen 16H – 4,946’

• Optimizing landing point and well design in Red Bull South acquisition area

• Wolfcamp C and 3rd Bone Spring test in Q3 to add co-development with Wolfcamp A

• First two 10,000 ft Wolfcamp A horizontals online in Barilla Draw Proper

> Lyda 33-40-1S 16H has best early production of any well Oxy has drilled in the Permian

> Toyah 4-9-1N 11H has Oxy’s 3rd

highest peak 24 IPLyda 16H highlight

26

Midland Basin - Merchant

• Operating cost <$3/boe

> Horizontal only development

> Infrastructure designed for full-field development

> Successful gas lift on majority of wells limits well failures and downhole cost

• Two play-leading benches under development

> Landing point optimized flow units

> Wolfcamp B performance +50%

> Oil cut from 61% to 77%+

Wolfcamp B Improvement = two high return development benches

Multi-bench program and operating efficiency create play-leading opex

Value-Based Development Increases Returns

$2.58

$-

$1

$2

$3

2017 YTD

Downhole Maint Surface Other

-

25

50

75

100

125

150

175

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

Cum

Oil

-MB

ONew WC B Design

All WC A Wells

Old WC B Design

Merchant Opex / BOESuccessful Development Planning from Inception Leads to Greenfield Operating Cost

• First wells online in 2014• No water hauling with truck• 46 horizontals online• Centralized facilities• Central compression for gas lift

27

Target Formation

Recent Well Results

Well NameLateral

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 29 21H 4,553 2,875 2,106 82%

Oxy 2017 Average 5,436 2,352 1,999 81%

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

Cedar Canyon 22-15 32HOxy 2017 Average

5,8685,227

2,2311,991

1,8521,748

75%74%

Wolfcamp XY

Patton 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 A

Janie 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%

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 in blue font was turned to production in 2Q 17.Average shown for all benches with multiple wells in 2017

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

28

Target Formation

Recent Well Results

Well NameLateral

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 HB Morrison 73HBig George 180 SW 3H

4,9277,576

962759

864571

75%57%

Wolfcamp A

Lyda 33-40-1S State 16HToyah 4-9 1N 11H

Buzzard State Unit #16HPeck State 258 #6HOxy 2017 Average

10,1649,8457,7004,2126,995

3,7243,0772,0502,2441,856

3,2022,0281,8221,7911,535

84%79%74%82%72%

Wolfcamp DF

Oppenheimer 188 1HNyala Unit 9B #3H

Oppenheimer 188 2HTeller 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 2HIron Mike 40 SE 2HOxy 2017 Average

7,0446,9477,3767,334

1,9541,8971,7031,411

1,5841,5441,4161,147

75%79%76%79%

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

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 in blue font was turned to production in 2Q 17.Average shown for all benches with multiple wells in 2017

Barilla Draw Type LogGreater Barilla Draw 

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 B

New

New

New

29*Source: Wood Mackenzie 2016 production, 3/2/17, company NWI% production rates, operators shown represent ~85% of Permian Basin daily productionGross Oxy operated wells including producers and injectors, and idle wells

 ‐

 50

 100

 150

 200

 250

 300

 350

 400

OXY CVX

PXD

APA

CXO

XOM

XEC

EOG

DVN

ECA

EGN

FANG

COP PE LPI

APC

KMI

SHER

IDAN

SHELL

RSPP

SINOCH

EM BHP

WPX

PERM

 RES.

ENDE

AVOR

QEP

MTD

RSM NBL

LINN

CPE

LGCY EPE

AREX

SSUMY

HESS

CWEI

REN

CRZO

PERM

IAN BAS

IN NET M

BOEPD OPERA

TED 

PRODU

CTION*

Liquids Gas

• 10,000 mi2 3D seismic• 130,000 mi2 2D seismic• 24,500 gross operated wells• ~10,000 gross OBO wells• 250 OBO wells since 2015

Advantages Through Scale

Largest Operator in the Permian

30

Permian Resources Growth Opex / boe

Permian Resources Legacy Opex / boe

Permian EOR Opex / boe

$2 - $4

$15 - $20

$5 - $20

2017 2018+

~$14/boe

Reducing Domestic Opex Through High-Margin Growth Barrels

Total Domestic Opex / boe

Domestic Production Mix

2017 2018+

FlatLegacyGrowth

EOR

Asset Area Opex Ranges

31

Appendix Contents

• Permian Updates

• Social Responsibility, Environmental, and Governance

• Journey to Digital Transformation

• Company Overview and Value Proposition

32

Reporting on Social Responsibility Since 1995

Environment, Social Responsibility and Governance are fundamental to our success and reputation as a Partner of Choice.

•

33

Stockholder Proposal on Managing Climate-related Risks

Stockholder Proposal• Produce a report assessing portfolio impacts of plausible scenarios that

address climate change, including the International Energy Agency's “450 Scenario”

Plan• Oxy will provide additional disclosure about the assessment and management

of climate-related risks and opportunities

> Describe management processes for identifying, assessing, and managing climate-related risks

> Evaluate potential impacts on business strategy of climate-related risks and opportunities under different future scenarios, including the IEA 450 scenario

> Supplement existing disclosures on greenhouse gas emissions with other information, including metrics used to manage performance

> Continue active and ongoing engagement with shareholders

34

Managing Climate-related Risks and GHG Emissions

Our Governance of Climate-related Risks and Opportunities

> Board of Directors' Environment, Health and Safety Committee provides leadership and oversight across all businesses with regard to climate risk, community resiliency and changes to regulatory frameworks

> Oxy is an active partner in developing industry-wide solutions

Business Focus and Competitive Advantages

> As the largest Permian operator, we can leverage existing infrastructure which provides significant life-cycle environmental and economic benefits

> Industry leader in carbon capture and storage via CO2 flooding with Enhanced Oil Recovery (EOR)

Management and Mitigation

> Received approval from U.S. EPA for the first-ever Monitoring, Reporting and Verification (MRV) Plan in 2015 for safely injecting and permanently storing CO2 in the Permian Basin

> Continued reduction in flared volumes with a goal of ‘no-routine flaring’ for all oil and gas businesses

Engagement and Disclosure

> Actively engaging with industry, investors, NGOs and other stakeholders

> Reporting our performance at Oxy.com and through investor-focused disclosures

35

5%

63%

32%Fresh WaterBrackish WaterRecycled Water

Water Infrastructure Drives Value & Environmental Benefits

$3.50

$2.10

$0.75

$-

$1

$2

$3

$4

Original Improved Current

Cost

/ b

bl o

f wat

erProduced Water Costs Frac Water Costs Water Recycling

Sand Dunes Cost Savings Per Barrel*$3.6MM savings from recycling program**

2017 Delaware Basin YTD Frac Water Usage

*Cost structure illustration based on Greater Sand Dunes development area**Savings calculated using total water recycled of 2.7 MM bbls since project inception (mid-2016) multiplied by the savings of $1.35 ($2.10/bblto $0.75/bbl)

Truck Produced Water+ Truck Frac Water

Pipe Produced Water+ Truck Frac Water

Recycle Produced Water for Frac Water

$1.50

$2.00$1.50

$0.60

• Fresh water only 5% of water used for completions in Delaware Basin

• Sand Dunes Water Recycling Project> 80% of frac water YTD from recycled

produced water

> 2.7 MM bbls recycled since project inception (mid-2016)

> Savings of $3.6 MM

> Expect to recycle ~6 MM bbls in 2017

Environmental Partner of Choice

36

CO2 EOR Process

Separate Oil, Gas

and Water

CO2 Recycled from Gas Plant

CO2 supplied from Pipeline

Produced GasCO2

Injection Production

Reservoir

Oil Sales

Gas & NGL Sales

Drive

WaterCO2 Water CO2

Miscible

Zone

Oil

Bank

AdditionalOil

Recovery

InjectorWellbore

ProducerWellbore

37

How does CO2EOR Work

Physics of Miscible CO2 EOR at Pore Scale

• Water injection (blue) recovers oil in large pores; leaving trapped oil (red) in small pores

• CO2 (yellow) dissolves and displaces trapped oil; leaving only heavy ends (brown) in the reservoir

• The process is normally finalized by injecting chase water after the CO2. Sequestered CO2 remains permanently trapped in the pore spaces

Water Injection

CO2 Injection

Water Injection

Oil (Red)

SequesteredCO2 (Yellow)

38

Appendix Contents

• Permian Updates

• Social Responsibility, Environment, and Governance

• Journey to Digital Transformation

• Company Overview and Value Proposition

39

• Smart Oilfield• Edge Computing• Internet of Things• Cloud and Mobility• Big Data and Analytics• Cognitive Service and

Machine Learning• UAV• Virtual Reality

• Real time Data Historian• Predictive Analytics• Advanced Surveillance

Technical Data Management

Production Optimization

Field Automation

Consolidated ERP Systems

Next Generation Production Optimization

• Institutionalized Processes and Tools

• Single reporting repository• Focus on analysis and

decision making

• Technical Data Consolidation• Global Well Naming Convention

• Integration of operational, technical and financial data

• Global Supply Chain• Single Chart of Accounts

• Standardized End Devices• Segregation of Automation Network• Secured Remote Access to Real time

Data• Process Historian

2001

2003

2005

2008

2012

Our Journey to Digital Transformation

40

Oxy

& In

dust

ry E

xper

tise

Data Management

Dat

a &

Ana

lytic

s D

omai

n Ex

pert

ise

• Visualization• Benchmarking• Exploitation & Exploration

Insight & Recommendations

• Bayesian Analysis• Survival Analysis• Uncertainty Analysis

• Design of Experiment• Statistical Learning (Machine Learning)• Spatial/Temporal Analysis

Statistical Methods

• Data Preparation & Tagging• Data Quality & Cleaning• Data Forensics & Profiling

Data Collection & Profiling

• Numerical and stochastic Simulation

• Signal Processing• Network Analysis

• Computational Intelligence• Natural Language

Processing• Image/Voice Processing• Data Structure & Classical

Algorithms

Opt

imiz

atio

nAr

tific

ial I

ntel

ligen

ce

Computational Methods

University Partnerships

O&G Industry Research

Outside Industry Research

Commercially Viable Algorithms

Vendors

IT

Key Levers

Data Science – Going Beyond Interesting

41

• Problem: Inefficient use of rig energy resulting in slow and higher cost drilling

> Downhole tool failures

> Wellbore quality

• Solutions: Oxy Drilling Dynamics

> Proprietary Oxy MSE equation

> Reduced drilling days

> Fewer tool failures

> Precision landing

• Better time to market and precision landing

Step Changing Performance

Identify Understand Engineer Implement

Bit Vibration

Increase BHA* St if fness

Pump Pressure

Alternative Dri l l P ipe

Directional Control

Weight Transfer

Redesign Bi t

Re-Engineer BHA*

Weight on Bit

Rat

e of

Pen

etra

tion

(ft/

hr)

31

22

16

12

30%

28%

25%

Drilling Days 7,500’ Lateral(Rig Release to Rig Release)

Real Time Monitoring from Anywhere

*BHA = bottom hole assembly

Driving Value @ the Bit

42

Driving Value @ the Bit + @ the Target

@ Bit Algorithm

• Predicts bit location using physics +machine learning

• Calculates dogleg severity, build/turn rate, motor yield

@ Target Algorithm

• Determines optimum build & turn rate, sliding and rotating lengths to reach target point

• Minimizes loss of weight on bit, tortuosity, drilling time, dogleg severity

Projection Distance

Max DLS limit = 11 degreesMax DLS limit = 14 degreesMax DLS limit = 24 degreesPlanned Trajectory

Actual Trajectory

• $325K avg. per rig savings

• Vendor performance metrics

• Increase in rate of penetration

• “Problem Well” avoidance

• Optimal path determination (staying in producing zone)

43

High Speed, Low Fidelity Reservoir Models

Historical/field data to calibrate and quantify uncertainty

Field decisions that optimize daily total field 

production

Maximize NPV honoring economic, operating, and well constraints

by generating thousands of what‐if scenarios

Observation WellInjection WellVent Well

Producing Well

Temp, Press

Production

Injection

Production Well DataInjection Well  Data    

Optimizer

Reservoir & Operational Facilities

Target=$100MM

Driving Value @ the Reservoir

Steam/Water/CO2• Leverage field data and new

data sources

• Optimize over larger areas

• Integrates w/existing workflow

• Significantly lower computational costs

44

Driving Value @ the Well

Lift System Diagnostic/Optimization

• Leverages artificial intelligence and pattern recognition

• Proprietary deviated well algorithms based on mechanical engineering+applied mathematics

Upcoming Opportunities

• Text and image analytics of unstructured data to drive efficiencies with chemical treatments, safety, failure detection, etc.

• Survival and risk analysis to identify odds of failure in advance.

• Combine maintenance cost factors and risk of failures to optimize preventative maintenance.

• Increase run life

• Earlier detection of failures

• Improve staff efficiency, quality

• Industry leading capabilities into Oxy’s proprietary lift platform (OxyLift)

Time

Risk vs Cost/Complexity

Risk of Failure Risk of Total Losses Risk of Additional Cost

45

Appendix Contents

• Permian Updates

• Social Responsibility, Environment, and Governance

• Journey to Digital Transformation

• Company Overview and Value Proposition

46

$0.50 $0.52 $0.55 $0.65 $0.80 $0.94 $1.21 $1.31 $1.47 $1.84 $2.16 $2.56 $2.88 $2.97 $3.02 $3.08

$0.50 $1.02 $1.57$2.22 $3.02

$3.96$5.17

$6.48$7.95

$9.79

$11.95

$14.51

$17.39

$20.36

$23.38

$26.46

$0.00

$4.00

$8.00

$12.00

$16.00

$20.00

$24.00

$28.00

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 4Q17Ann.

Annual Dividends Paid

Cumulative Dividends Paid

46Note: Dividends paid as per the Record Date

Delivering Consistent Annual Dividend Growth

($/share)2002 – 2016: Oxy dividend CAGR 13.7% vs S&P CAGR 7%

47

Value Growth• Consistent top-tier ROCE

performance in industry

• Organizational structure, process and culture have been aligned to deliver returned based growth

• Long history of returns metrics in executive compensation

> 2017: EBITDA /PPE

> 2018: ROCE

*Competitors ROCE represents a simple average of APA, APC, COP, CVX, DVN, EOG, HES, MRO and XOM

(30%)

(20%)

(10%)

00%

10%

20%

30%

2008 2009 2010 2011 2012 2013 2014 2015 2016

Competitors ROCE*OXY ROCE

Value Growth - Annual ROCE for Oxy vs. Average of Competitors

48

Value Growth

Focus on value-driven growth - Top quartile returns

Positioned to return to double-digit returns

(30%)

(20%)

(10%)

0%

10%

HES DVN CXO APC MRO APA EOG COP PXD OXY CVX XOM

2016 ROCE*

*Calculated based on public information and on a consistent basisCompanies listed alphabetically : APA, APC, COP, CVX, CXO, DVN, EOG, HES, MRO, PXD, XOM

49*Competitor Peers include APC, CVX, CXO, DVN, EOG, HES, MRO, PXD. Excludes APA, COP, XOM due to negative F&D.

2016 F&D (Organic) $/Boe19.27

17.19

13.37

11.73 11.41

9.59

6.86 6.51 6.45

0

5

10

15

20

1 2 3 4 5 6 7 8 OXY

$/B

oe

Competitor Peers*

Value Growth – Significantly Reduced Development Cost

50

Oman: Assisted with the discovery and started development of Safah Field in

1982. A 15 year contract extension was signed for Block 9 this year.

Blocks 27 and 53 expire in 2035. Block 62 expires in 2028.

Oman: Assisted with the discovery and started development of Safah Field in 1982. A 15-year contract extension was signed for Block 9 this year. Blocks 27 and 53 expire in 2035. Block 62 expires in 2028.

Colombia: Discovered giant Cano Limon field in the early 1980s. Several contracts that currently range from 6 years up to the economic life of field.

Long term contracts

with upside potential

Longest Legacy International Operations: Colombia and Oman

51

ISND and ISSD: Offshore development in Qatar. ISND contract for 25 years initiated in 1994. ISSD contract expires in 2022.

Dolphin: Premier transborder pipeline delivering gas from Qatar to Abu Dhabi and Oman. Agreement was initiated in 2007 for a 25-year term.

Al Hosn: 30-year joint venture with the Abu Dhabi National Oil Company, (“ADNOC”) began in 2011 to develop the giant sour gas field in Abu Dhabi. Largest ultra sour gas plant in the world. Al Hosn is a world-class mega-project.

Additional Core Middle East Assets