occidental petroleum corporation february 14, 2018...4q17 results *see significant items affecting...

February 14, 2018Occidental Petroleum Corporation

Fourth Quarter 2017Earnings Conference Call

2

Cautionary Statements

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.

3

Occidental Petroleum

• 2017 Highlights and Beyond

• Pathway to Breakeven Progress

• Financial Summary and Guidance

• Permian Resources Update

• International Update

• Closing Remarks

4

Improved our Cash Flow in 2017 to Accelerate Breakeven Plan

CO2-EOR Advancement> Sequestered over ~800,000 MT of

anthropogenic CO2 as recognized by Oxy’s EPA approved MRV plan

> Four unconventional EOR technical pilots since 2014

Cost Innovation> Successful completion of SL2 multi-

lateral pilot and construction of logistics hub

> Successful implementation of Oxy Drilling Dynamics to international operations

Well Productivity Improvement> Permian Resources average 6 month

cumulative production increased over 20% compared to 2016

> Achieved record rates across 8 benches in Permian Resources

All-in Reserves Replacement> 187% total company, 318% total

Permian

Cash Flow Enhancement> International upstream assets

generated over $1 Bn of free cash flow> Export volumes of 190 MBopd from

Ingleside terminal and successful VLCC docking

Asset Optimization> Sold South Texas Gas position to

add two additional rigs in Permian Resources

> Sold non-core Permian Resources Acreage for synergistic CO2-EOR position

Asset Start-ups> Completed two major chemical

projects on-time and on-budget –Ethylene Cracker and 4CPe Plant

International Contracts> Extended Block 9 and signed

Block 30 in Oman

Advanced Technologies and Operations

Increased the Value of our AssetsEnhanced Our Portfolio

5




1 Cash outflows excluding working capital2Refer to 4th Quarter Earnings Release for definitions of F&D calculations

Cash Inflows Cash Outflows

Net Asset Sales

Tax Refund

Capital Expenditures

Dividends

Operating Cash Flow

$5.8 Bn

6 Month Cumulative

Prod

uctio

n

Permian Resources

1

2017

Delivering Long-term Sustainability of our Value Proposition

5 Year 3 Year 2017

F&D

Cos

ts p

er B

OE

(All-

in)2

$6.0 Bn $17.96 $17.22

$8.53

RRR187%

2016

6

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

Annual OperatingCash Inflows

Sustaining Capitalat

$50 WTI

GrowingDividend

5%-8% ProductionGrowth

Net DebtReduction &Opportunistic

Growth

ShareRepurchases

Disciplined Cash Flow Priorities Following Breakeven Plan Achievement

1Estimated cash flows exclude working capital

Estimated Cash Flows ($ Bn)1

CFFO$50 WTI

CFFO$60 WTI

$50 WTI: Value Proposition Fully Funded

Sustaining Business

Dividend Growth

Production Growth

$50+ WTI: Opportunistic Balance Sheet and Growth

Strong Balance Sheet

$60+ WTI: Opportunistic Growth and Share Buybacks

Long

-term

Sus

tain

abili

ty o

f our

Val

ue P

ropo

sitio

n

ROCE Leadership

7

$1.9

$0.5

$0.8

$0.1 $0.3

$0.3

$3.9

2018 Capital Program by Asset ($ Bn)

Chemicals

Midstream

Exploration & Other

International

Permian EOR

Permian Resources

1Sustaining capital based on a 2018E production decline rate of 15%

2018 Capital Will Deliver Breakeven Plan & 8% to 12% Production Growth

Oil & Gas

2018 Capital Program by Type

TotalCompany Sustaining1

58%Growth

39%

Exploration 3%

DCW74%

Facilities18%

Maintenance5%

Exploration3%

8







• Closing Remarks

9

0.0

1.0

2.0

3.0

4.0

5.0

6.0

4Q17 Annualized CFFOAdjusted to $40 WTI

Chemicals Midstream & Marketing Remaining 50Mboed Permian

Resources Production

Cash Flow Neutral at$40 WTI

Increase in CashFlow at $50 WTI

Cash Flow Breakevenwith 5%-8% Growth

at $50 WTI

$3.9

$4.0 $4.1$4.5

Current Dividend

$2.4

Sustaining Capital$2.3

~$120 MM per $1 Change oil price

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 C

ash

Flow

($ B

n)

Growth Capital$1.0

Cash Flow Neutral at $40:Dividend with Flat Production

Pathway to Cash Flow Breakeven at Low Oil Prices

$4.5$4.3 Actual

4Q PositiveMidstream Seasonality

10

$0.2

$0.3

$0.9

$0.2

0.0

0.2

0.4

0.6

0.8

1.0

Chemicals Midstream Permian Resources Production

Other Improvements

Annualized Cash Flow From Operations Improvements ($ Bn)

Breakeven PlanAchieved since 1Q17

Seminole San Andres Synergy Value

Achieved

Chemicals $50/ton Caustic

Soda Realizations Achieved

4CPe Plant Ramp-up

through 1H18

Al Hosn Optimization and Crude Terminal Capacity Upgrade

Remaining

50 Mboed Growth

Remaining

Achieving Goals to Cash Flow Breakeven at $50 WTI4CPe Plant operations started in December 2017, on-time and on-budget. Manufacturing ramp-up will occur through 1H18.

Marketing differential continued to improve substantially surpassing our $2.10 per barrel breakeven plan assumption

Added 20 Mboed of Permian Resources Production sequentially and 30 Mboed since 1Q17 net of ~5 Mboed divestment

11

Current Cash Balance Will Fund Plan to Breakeven assuming $50 WTI in 2018Cash flow outspend through the completion of our plan is covered by our cash balance but total liquidity includes:

• Current cash balance: $1.7 Bn

• Portfolio management: $0.5 - $2.0 Bn

• PAGP units: $0.6 Bn

• Undrawn revolving credit facility: $3.0 Bn

We do not anticipate increasing debt levels to achieve plan

(2.0)

(1.0)

-

1.0

2.0

3.0

4.0

5.0

6.0

Operating Cash Flowat $50 WTI

Dividends Capital Expenditures Available Liquidity

Estimated Cash Flows Through End of 2018 at $50 WTI1

Cash Balance

PAGP

Portfolio Management

Cash Flow Deficit

$B

n

$3.9 Bn

1Estimated cash flows exclude working capital

12







• Closing Remarks

13

4Q17 Results

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

Total reported production (Boed) 621,000

Total Permian Resources production (Boed) 159,000

Reported diluted EPS $0.65

Core diluted EPS* $0.41

4Q17 CFFO before working capital & other $1.5 Bn

4Q17 capital expenditures $1.2 Bn

Cash balance as of 12/31/2017 $1.7 Bn

4Q17 Actual versus Guidance Reconciliation

Boed

PSC Impact 5,000

Permian Third-Party 4,000

Permian OBO Timing 2,000

Permian Weather 1,000

Total ~12,000

14

2017 Cash Flow and Cash Balance Reconciliation

Beginning CashBalance 1/1/17

CFFO Before WorkingCapital

Change in WorkingCapital

Dividends Capital Expenditures Asset Sales Acquisitions/Other

Tax Refund Ending Cash Balance12/31/2017

$1.7

($2.3)$4.7

$2.2

($3.6)

($0.3)

$1.4$0.8

($1.1)

($ in Bn)

15

2018 Guidance

Oil & Gas Segment

• FY 2018E Production

> Total production of 640,000– 665,000 boed

> Permian Resources production of 195,000 – 209,000 boed

> International production of 286,000 – 297,000 boed

• 1Q18E Production

> Total production of 592,000 – 603,000 boed

> Permian Resources production of 169,000 – 173,000 boed

> International production of 265,000 – 271,000 boed

> Al Hosn Gas production of 58,000 – 59,000 boed

> Dolphin production of 36,000 boed

• Commodity Price Assumptions

> 1Q18E assumes $60 WTI / $65 Brent

> 2Q18E– 4Q18E assumes $55 WTI / $60 Brent

Production Costs – FY 2018E

• Domestic Oil & Gas: ~$12.50/ boe

Exploration Expense

• ~$20 MM in 1Q18E

• ~$150 MM in 2018E

DD&A – FY 2018E

• Oil & Gas: ~$13.50/ boe

• Chemicals and Midstream: $715 MM

Midstream

• $10– $30 MM pre-tax income in 1Q18E

> Midland – MEH spread of $3.00 - $3.25 / boe

• $200 - $300 MM pre-tax income in 2018

> Midland – MEH spread of $2.50 - $3.00 / boe

Chemical Segment

• ~$250 MM pre-tax income in 1Q18E

• ~$1,000 MM pre-tax income in 2018E

Corporate

• FY 2018E Total Company tax rate: 36%

• FY 2018E Int'l tax rate: 45%

• Interest expense of $85 MM in 1Q18E

16

Cash Flow Sensitivities in 2018

Oil & Gas

> Annualized cash flow changes ~$110 million per ~$1.00 / barrel change in oil prices

• ~$80 million per ~$1.00 / barrel change in WTI prices

• ~$30 million per ~$1.00 / barrel change in Brent prices

> Annualized cash flow changes ~$40 million per ~$0.50 / Mmbtu change in natural gas prices> Annualized production changes 800 – 1,000 boed per ~$1.00 / barrel change in Brent prices

Chemicals> Annualized cash flow changes ~$30 million per ~$10 / ton change in realized caustic soda prices

Midstream> Annualized cash flow changes ~$45 million per ~$0.25 / barrel change in Midland to MEH spread

17







• Closing Remarks

18


Permian Resources> Four unconventional EOR technical pilots

since 2014

> Constructed Aventine Logistics Hub

> Successful SL2 multi-lateral pilot

Permian EOR> Sequestered over ~800,000 MT of

anthropogenic CO2 as recognized by Oxy’s EPA approved MRV plan

Subsurface and Data Analytics> Geomechanics and petrophysical

breakthroughs provide well productivity improvements through landing zone and stimulation designs

> Dysfunction detection and prevention analytics for artificial lift and drilling

Permian Resources> Added 750 undrilled locations to <$50

breakeven inventory

> 2017 F&D* of $8.57 and 373% RRR*

> New well average 6 month cumulative production increased over 20% compared to 2016

> Improved 4Q17 operating costs 9% YoY to a record $7.63/boe

Permian EOR> Added 100 Mmboe of potential resource with

<$6.00 future development cost

> 2017 F&D* of $7.66 and 111% RRR*

> Reduced SSAU operating costs more than $5.00/boe and increased production 3,600** boed since Aug 1st

Permian Resources> Sold $600 MM of assets beyond current

10 year development plan

> Completed 17,000 net acre trades for improved development value

> Added a new modular development area in New Mexico – Turkey Track

Permian EOR> Acquired additional interest and

operatorship in the CO2-EOR Seminole San Andres Unit

> 1st injection in one new CO2 flood and six expansions

South Texas> Sold assets and reinvested proceeds

into Permian Resources



*2017 Finding and Development Cost (F&D) and Reserves Replacement Ratio (RRR) calculated using organic reserve additions. Refer to 4th Quarter Earnings Release for definitions of F&D calculations**Total gross production increase at the Seminole San Andres Unit (SSAU).

19

Added 750 Horizontal Locations in 2017 with <$50 Breakeven

17 years of inventory <$50 breakeven with 10 rigs

Note: Breakeven defined as positive NPV 10 as of 12/31/2017

Und

rille

d Lo

catio

ns

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4Q16 <$50 BE Drilled 2017 Demonstrated CostImprovement

DemonstratedWell Performance

LandImprovement

EvaluatedNew Acreage

Tax Reform 4Q17 <$50 BE

3,132

Midland Basin

Texas Delaware

Basin

(118)

175

150150

150

125

New Mexico

Delaware Basin

2,500

Exceeded <$50 Inventory Growth Goal

> Added 750 locations in 2017 vs 400 location goal

> Increased <$50 average lateral length from 8,400 ftto 8,500 ft

> Executed 17,000 net acre trades to enable longer laterals and consolidated facilities

20

-

50

100

150

200

250

300

350

0 30 60 90 120 150 180

3rd Bone Spring Performance

-

50

100

150

200

250

300

350

0 30 60 90 120 150 180

2nd Bone Spring Performance2

Excellent Results in Greater Sand Dunes

Notes: 1Three stream production results. 2Excludes two 2nd Bone Spring wells shut-in for extended period for offset frac

Sustainable Step Change in Well Results De-risks Breakeven Plan

Oil (Bod) Gas (Boed)NGL (Boed)

18 new top tier wells in 4Q17

Includes 1 Avalon appraisal• 1,818 30 day Boed

• Improvement opportunities

Sustained productivity• 3Q and 4Q Peak 30 Boed per

1,000 ft of lateral~ 470

2H17 Wells2 – Peak 30D Production Rates1

2016 Average10 Wells ~5,000’

Cum

ulat

ive

Prod

uctio

n (M

boe)

Days Online

2H17 – 7 Wells ~7,900’

2016 Average4 Wells ~5,100’

2nd Bone Spring

3rd Bone Spring

Wolfcamp XY

2H17 - 12 Wells ~6,500’

1Q18 Record WellCC 27/28 #44H

9,800’ WC XY1

2 W

ells

~6

,50

0'

7 W

ells

~7

,90

0'

3 W

ells

~5

,40

0'

2,987

3,543

2,372

-

1,000

2,000

3,000

4,000

New Record Well

Online Jan 2018 Cedar Canyon 27/28 Fed 44H

Wolfcamp XY – 9,800’

6,111 30-Day Boed8,361 24-Hr Boed

21

3Q17 4Q17 1Q18E 2Q18E 3Q18E 4Q18E

169 - 173

184 - 199

206 - 220

220 - 244

159

Permian Resources Production (Mboed)

Permian Resources Value-based Production GrowthBreakeven Plan Milestone Achieved in 3Q18

Dec-2017 Exit at 172 Mboed

4Q17 Production Impacts

• ~3 Mboed: 3rd Party Downtime

• ~2 Mboed: OBO Timing

• ~1 Mboed: Weather Downtime

1Q18 Production Notes

• ~2 Mboed: January weather

• Development optimization shifts wells online to 2Q

• Planned artificial lift installation

Bre

akev

en P

lan

Achi

eved

+80

Mbo

ed fr

om 1

Q17139

QoQ Growth: 14% 7% 12% 11% 9%

Wells Online: 28 45 34 – 38 59 – 63 53 – 57 41 – 45

+20

Mbo

ed fr

om 3

Q17

~45% Production Growth

22

D&C70%

Facilities15%

OBO10%

Other5%

Greater Barilla Draw ~4 rigs

Permian Resources Acreage

Permian EOR Acreage

Greater Sand Dunes ~5.5 rigs

Turkey Track ~0.5 rigs

2018 Capex$1.9 B

13 Rigs195 Wells Online

11Development

Rigs

2 Net Non-op Rigs

180 Development

Wells

2018 Capital by Type

2018 Well Count 2018 Rig Count

Permian Resources 2018 Focused Development

Permian Resources 2018 Program

Midland Basin ~1 rig

• Appraise 6 new benches

• Additional Unconventional CO2-EOR pilots

• Logistics hub in New Mexico online

• Logistics solutions in TX Delaware

• First 2.5 mile laterals

• Expanding produced water recycling

15 Appraisal Wells

23







• Closing Remarks

24

2017 International Highlights and 2018 Plan

> 2017 production of 298 Mboedgenerated over $1 Bn of free cash flow at ~$55 Brent

> Pipeline of potential short and long-cycle projects

> Best international HES performance in Oxy history Oman Block Position

201

7 M

ilest

ones

201

8 P

lan

> Record Al Hosn Gas production of 71 Mboed achieved via plant optimization

> Milestones of 1 Bn barrels of oil produced in Oman and record gross production from the La Cira Infantas field in Colombia

> Extended Block 9 and signed Block 30 which brings Oman acreage to 2.3 Million

> Step-out wells in Oman and Colombia added 50 MM barrels of net resource

> Al Hosn Gas Plant debottlenecking increases capacity by 11% for $10 MM of capital. Peak-rate of ~83 Mboed will be reached in 3Q18.

> Sanction TECA Steamflood in Colombia after 2017 pilot

> Continue step-out program in Oman and Colombia

Al H

osn

Gas

Pla

nt

Al Hosn Gas – Project Execution and Operational Excellence• World-class, state-of-the-art sour-gas project delivered on-time and on-budget

• Production and throughput continues to improve with operational excellence

• Modifications will occur during turnaround beginning in 1Q18 and ending in 2Q18

• Minimal capital will be required

Al Hosn Gas Plant 25

-

10

20

30

40

50

60

70

80

90

2016 2017 2018E 2019E 2020E

Al Hosn Gas Production(Mboed)

Original Plan

Current Plan

2018Debottlenecking$10 MM Capital

2017OptimizationNo Capital

Initial Production

26

Complex, Major Project CapabilityIndustry-leading execution performance

Compared to industry average of >20% capital overruns and 9 months delay

Domestic Projects• Ingleside, TX – Ethylene Cracker• Ingleside, TX – Oil Terminal• Geismar, LA – 4CPe Plant

International Projects• UAE – Al Hosn Gas• Oman – Block 62 Gas Plant

Recent Major Projects Delivered On-time and On-budget

27







• Closing Remarks

28

Short and Long-term Executive Compensation Changes

1 For CEO, 80% of target value is linked to company performance; 20% is based on individual performance. 2 CROCE defined as (Net Income + DD&A + After-tax Interest Expense) / Average (Total Debt + Total Equity).

Expanded use of returns-based metrics for incentive compensation

Short-term Incentives Long-term Incentives

15% of CEO annual bonus1 is determined by CROCE2, with a

performance target of 18%

> Improved alignment with shareholders

25% of CEO long-term incentive compensation is determined by

CROCE, with a performance target of 20%. CEO long-term incentive is

70% performance-based

> Consistent with our historical practices

CROCE-based compensation

~20%2018 CEO Compensation

at Target

Appendix

30

Average Shareholder Payout Ratio (%)1

Shareholder Distributions Over the Last Three Years (2016 – 2014)

9%

6%5% 5% 5% 5%

4%

1% 1%

1 OXY 2 3 4 5 6 7 8

66%

56% 56%

44%

30%27%

22%

14%9%

1 OXY 3 4 6 2 5 7 8

1 Source: Company filings and Factset. Shareholder distributions include dividends and share repurchases. Peers 1 – 8 include APC, APA, COP, CVX, EOG, HES, MRO, XOM

> Strong history and commitment to shareholder returns

> Confidence in asset capabilities and conservative balance sheet allows us to sustain dividend through cycle

> Improving payout ratio through high-margin growth with leadership in ROCE

54

28

10 95 3 2 1 1

3 4 OXY 6 1 5 2 7 8

5.325.02

4.294.28

2.622.30

0.990.85

0.78

1 4 3 OXY 5 6 2 7 8

Average Shareholder Payout per Share ($/Sh)1

Cumulative Distributions ($Bn)1

Average Shareholder Distribution Yield (%)1

31

Strong Balance Sheet - Oxy Credit Ratings Vs. Peers

Source: Factset, 02/12/2018

Company S&P Ratings

S&P Outlook

Moody’s Ratings

Moody’s Outlook

XOM AA+ Negative Aaa StableCVX AA- Negative Aa2 StableOXY A Stable A3 StableEOG BBB+ Stable Baa1 StableCOP A- Stable Baa1 StablePXD BBB Stable Baa3 StableAPA BBB Stable Baa3 StableNBL BBB Negative Baa3 StableDVN BBB Stable Ba1 StableAPC BBB Stable Ba1 StableMRO BBB- Stable Ba1 StableHES BBB- Stable Ba1 StableCXO BBB- Stable Ba1 PositiveCLR BB+ Stable Ba3 PositiveWPX B+ Stable B2 StableWLL BB- Stable B3 Positive

32

Appendix Contents

• Social Responsibility, Environment, and Governance

• 2017 Reserves

• Permian Updates

• Chemicals and Midstream Updates

33

Occidental’s First Climate Report will be Released in 1Q 2018

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

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

Report Highlights• Board and Management’s process for identifying, assessing, and managing

climate-related risks and long-term strategy for sustainability

• Results from scenario analysis including the International Energy Agency’s “450 Scenario” and newly released “Sustainable Development Scenario”

• Capital planning and risk assessment process improvements to incorporate additional climate-related risks into future project evaluations

• Metrics, targets and commitment to continued and improved transparency in reporting

• New climate-related metric included in CEO compensation plan for 2018

• Overview of Occidental’s world-class CO2 EOR assets and industry leading expertise in CO2 sequestration

Report will be posted on the Social Responsibility section of Oxy.com

34

Oxy Safety Culture and Strong Performance

Committed to the highest standards of conduct

Fostering a culture of safety excellence and continuous improvement to achieve a zero-incident safety record, everywhere we operate

Stop Work Authority policy requires employees and contractors to halt production, shut down any equipment or stop any job to prevent an accident or environmental incident

In 2017, Oxy had its best-ever employee safety performance record

•Incidents and Cases per 100 Workers

Global Employee Injury and Illness Incidence Rate

0.33

0.3

0.380.36

0.25

0.2

2012 2013 2014 2015 2016 2017

35

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

er

Produced Water Costs Frac Water Costs Water Recycling

Greater Sand Dunes Cost Savings Per Barrel*

$7.8MM savings from recycling program**

Delaware Basin Frac Water Usage

*Cost structure illustration based on Greater Sand Dunes development area**Savings calculated using total water recycled of 5.8 MM bbls since project inception (mid-2016) multiplied by the savings of $1.35 ($2.10/bbl to $0.75/bbl)e

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

• Increasing Recycled Water Usage from ~30% to ~50% in 2018

• Greater Sand Dunes Water Recycling Project

> 80% of frac water YTD is recycled produced water

> 5.8 MM bbls recycled since project inception (mid-2016)

> Savings of $7.8 MM

11%

57%

32% Fresh Water

Brackish Water

Recycled Water

10%

40%50%

2017 Actuals 2018 Plan

3636

Injection well

CO2

Drivewater CO2 Water

MiscibleZone

OilBank

Producer wellbore

Producing Reservoir

Production

Oil Sales

Produced Gas

Oil / Water / Gas Separator

Gas PlantGas & NGL

SalesMakeup CO2

Supplied from Pipeline

CO2 Recycled from Gas Plant

Makeup CO2Supplied from Anthropogenic

Sources

Emissions Reducing Opportunity

C02 EOR Process

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


• 2017 Reserves

• Permian Updates


39

Total Company Reserve

Replacement 2017

187% All In

162% Organic

YE 2016Reserves

Production* Additions Acquisitions &Sales

YE 2017Reserves

2,406 (220)

3572,59855

74% Proved Developed

75% Liquids

All reserves are in Mmboe. *2017 Production includes South Texas.

2017 Reserve Additions Through Program Execution200 MMBOE Reserve Additions prior to price revisions

40

Successful Drilling and A&D Programs Leading to Lower F&D Costs

> Positive total-company performance revisions

> Improved productivity and lower well costs in Permian Resources

> Purchased ~80 MM Boe more barrels than sold in Permian transactions

> Expanded capacity at Al Hosn Gas> Successful extension of Oman Block

9 contract

$18.05 $18.36

$8.34

5 Year 3 Year 2017

F&D

Cos

ts (O

rgan

ic)*

*Refer to 4th Quarter Earnings Release for definitions of F&D calculations.Occidental incurred approximately $0.7 Billion to convert proved undeveloped reserves to proved developed reserves.

$17.96 $17.22

$8.53

5 Year 3 Year 2017

F&D

Cos

ts (A

ll So

urce

s)*

Program Execution Highlights

41

2017 Total Company Reserve Replacement

MMBOE2016 YE Proved Reserves 2,406Production (220)Revisions of Previous Estimates 151Improved Recovery 201Extensions & Discoveries 5Total Organic 356Purchases & Sales 552017 YE Proved Reserves 2,598

Total Additions (All In) 412Reserve Replacement (All in) 187%Reserve Replacement (Organic) 162%

42

2017 U.S. Reserve Replacement

MMBOE2016 YE Proved Reserves 1,353Production (111)Revisions of Previous Estimates 109Improved Recovery 149Extensions & Discoveries 0Total Organic 258Purchase & Sales 552017 YE Proved Reserves 1,555

Total Additions (All In) 313Reserve Replacement (All in) 282%Reserve Replacement (Organic) 232%

43

Appendix Contents


• 2017 Reserves

• Permian Updates


44

0

5

10

15

20

25

30

Jan - Jul 2017 Avg Sep-2017 Dec-2017

MB

oed

SSAU Gross Production

Creating Value at the Seminole San Andres Unit

Increased Production 3,600 Boed or 16%

$0

$100

$200

$300

$400

$1/Boe $2/Boe $3/Boe $4/Boe $5/Boe

Value of Opex Synergies ($MM PV10)

Acquired Interest Existing Interest

• Increased plant inlet volume 32%• Reduced flaring by 60%• Implemented surveillance workflows

Reduced Redrill Capital Costs by 36% Greater than $5/boe Opex Reduction

0

50

100

150

200

250

300

350

Prior Operator AFE Oxy Planned Oxy Actual

IP 3

0 B

oed

SSAU Redrill Well Productivity

• Savings utilizing Permian scale• Implemented Oxy well design• Operating capability improved efficiency

$0.0

$0.5

$1.0

$1.5

Prior Operator AFE Oxy Planned Oxy Actual$

MM

SSAU Redrill Well Cost

$0

$100

$200

$300

Oxy Planned Oxy Actual

$ M

M

SSAU Lift Revision Cost

$0

$10

$20

$30

Prior Operator Opex Oxy Current Opex Oxy Opex Target

Ope

x$

/boe

SSAU Opex

>$5/boereduction to-date

• Optimized Purchased Injectant• Well Enhancement Execution• Optimized Resource Deployment

45

-

50

100

150

200

250

0 30 60 90

Cum

ulat

ive

MB

OE

Turkey Track - New Modular Development AreaNew Mexico Modular Development AreaLeveraging Permian Scale to Realize Value in Smaller Development Areas

• Turkey Track – North Delaware Basin> Greater than 40% all-in ROR at $50 WTI

> Successful appraisal of 3rd Bone Spring

> Well costs 25% below target costs at $7.7MM per well – 10,000’

> Drilled in 20 days

> Achieved 12 frac stages per day

• Similar scale opportunities available in other areas of the Permian Basin

Southeast New Mexico

Greater Sand Dunes

Innovative Development Provides Scale Advantages to Regional Areas

Multi-bench potential

Modular Facilities

Utilizes Basin Synergies

Turkey Track – Cumulative 30 Day MBOE

3rd Bone Spring1 well ~ 9,800’

Future 3rd Bone Spring Development

Days Online

2nd Bone Spring4 wells ~ 9,700’

Future 2nd and 3rd Bone Spring Development

46

2017 Barilla Draw proper– Wolfcamp A Optimized Landing Point Results

-

50

100

150

200

250

- 30 60 90 120 150 180

Days Online

Average of 2017 10,000 ft wells (3)

Average of 2017 5,000 ft wells (5)

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

$5.17

$1.94

$3.93 $4.59

$9.62

$-

$2

$4

$6

$8

$10

Red Bull South Mentone Lockridge Barilla - Birds of PreyArea

Tx Delaware - TotalOperated Fields

Greater Barilla DrawOperating Excellence & Strong Results

Strong results across multiple fields > Core Barilla Draw continues excellent

results and improvement from previous years

> Tier 1 results in Wolfcamp A and B in Red Bull South acquisition acreage

> Successful appraisal of 2nd Bone Spring and 3rd Bone Spring in 2017

Horizontal development continues to improve margins

> Four fields with horizontal wells have at or below $5/boe operating cost

Hz Development Yields Low Operating Costs

Four Greater Barilla Draw fields with all or almost all horizontal development

Includes ~700 vertical wells

Hz well count: 59 11 11 18

Avg. Hz well age: ~2 years ~ 2 years ~2 years ~2.5 years

Cum

MB

OE

47

-

30.00

60.00

90.00

120.00

150.00

180.00

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

Cum

Oil

-MB

O

Midland Basin - Merchant

Operating cost <$2.75/boe

> Horizontal only development

> 10,000 ft wells go-forward

> Centralized facilities and ample Oxy disposal capacity

> Infrastructure in place to increase marginsTwo play-leading benches under development

> Landing point optimized flow units

> Strong performance in Wolfcamp A and Wolfcamp B benches

> Wolfcamp B performance +22%

Wolfcamp B Improvement = two high-return development benches

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

$2.71

$-

$1

$2

$3

2017 Total

Surface Other Total

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

• First wells online in 2014• 55 horizontals online• Centralized facilities• No water hauling with truck• Central compression for gas lift• Gas lift limits well failures and

downhole cost

New WC B Design

All WC A Wells

Pre 2017 WC B Design

48

Target FormationRecent 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 Patton MDP1 18 Fed 23H 4,108 2,008 1,509 76%

1st BSS Cedar Canyon 23 2H 4,025 1,428 972 70%

2nd BSS

Cedar Canyon 23 Fed Co 6H 7,241 4,518 3,963 75%Palladium MDP1 7/6 Fed Com 6H 9,852 4,731 3,404 81%Palladium MDP1 7/6 Fed Com 5H 10,040 4,456 3,213 81%Cedar Canyon 21 Fed 022H 4,596 5,162 3,182 76%Patton MDP1 18 Fed 7H 4,581 4,817 3,099 78%Oxy Total 2017 Average 6,475 3,055 2,247 80%

3rd BSS

Cedar Canyon 21-22 FED Com 32H 9,851 5,834 3,916 68%

Cedar Canyon 23 24 Fed 32H 7,235 6,497 3,693 69%Cedar Canyon 23 24 Fed Com 34H 7,172 4,876 3,338 73%Cedar Canyon 21 22 Fed Com 34H 9,820 3,751 3,286 75%Cedar Canyon 21 22 Fed Com 33H 9,758 3,730 3,192 77%Oxy Total 2017 Average 7,303 3,693 2,688 74%

Wolfcamp XY

Patton 18 Fed 6H 4,394 2,774 2,150 71%Calmon 35 Fed 171H 4,453 2,956 2,107 68%Cedar Canyon 16 33H 4,418 2,397 2,049 71%Cedar Canyon 16 34H 4,235 2,287 1,967 70%Oxy Total 2017 Average 5,187 2,595 2,032 72%

Wolfcamp AJanie Conner 204H 4,500 1,980 1,221 78%B Banker 226H 4,400 1,874 1,030 76%Cedar Canyon 27 10H 4,215 1,645 1,486 73%

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.Wells in blue font were turned to production in 4Q17. All BOE Data is based on two-stream well tests.Average shown for all benches with multiple wells in 2017.

Greater 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-Y

Wolfcamp A

Wolfcamp D

6,0

00

ft

New

New

New

New

49

Target FormationRecent Well Results

Well Name Lateral Length (ft)Peak 24 Hr

(boed)Peak 30 Day

(boed)Oil (%)

Avalon Evaluating

1st BS Evaluating

2nd BS

Collie A East N63H 9,725 1370 1155 81%

Aardvark State 6 2H 4,947 1254 821 87%

Roan State 24 #51H 4,514 993 762 83%

3rd BSBig George 180 SW 3H 7,576 759 571 57%

Morrison, HB 73H 4,927 854 864 75%

Wolfcamp A / DF

Lyda 33-40-1S State 16H 10,164 3,724 3,202 84%

Toyah 4-9 1N 11H 9,845 3,077 2,028 79%

Hamlton 12H 9,380 2,604 2,023 65%

Oppenheimer 188 1H 4,500 2,451 1,907 82%

Buzzard State 21 16H 7,598 2,050 1,822 74%

Allen 39 11H 4,971 1,917 1,755 80%

Oxy Total 2017 Average 7,003 1,735 1,384 77%

Wolfcamp B

Agate 179-142-3S 25H 7,439 2,088 1,731 73%

Daytona Unit 1B 2H 6,947 1,897 1,544 79%

Agate 179 142 2S 21H 7,197 1,941 1,469 80%

Manhattan 183W 1H 7,092 1,831 1,460 75%

Oxy Total 2017 Average 7,867 1,520 1,205 77%

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.Wells in blue font were turned to production in 4Q17. All BOE Data is based on two-stream well tests.Average shown for all benches with multiple wells in 2017. Wolfcamp DF wells now combined with Wolfcamp A wells.

Greater 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 A/DF

Wolfcamp C

4,5

00

ft

Wolfcamp B

New

50

AVG Lat Length (ft) 4,811 5,789 6,933 ~7,500 6,636 6,204

0

20

40

60

80

100

120

2015 2016 1H 17 2017 Expected Top Peers2017

Top Peers2016

0

20

40

60

80

100

120

140

160

180

200


Top Peers2016

0

20

40

60

80

100

120

140

160

2015 2016 1H 17 2017Expected

Top Peers2017

Top Peers2016

0

50

100

150

200

250


Top Peers2016

Permian Resources Wells Continue to Improve

Top Peers is an average of Peers in the Top 15 based on # of wells online within the respective year 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.

6 M

onth

BO

ECu

mul

ativ

e Pr

oduc

tion

6 M

onth

BO

ECu

mul

ativ

e Pr

oduc

tion

6 M

onth

BO

E Cu

mul

ativ

e Pr

oduc

tion

6 M

onth

BO

ECu

mul

ativ

e Pr

oduc

tion

AVG Lat Length (ft) 4,169 4,906 5,430 ~6,000 5,953 5,235

New Mexico Bone Spring

New Mexico Wolfcamp

Texas Delaware Wolfcamp

Texas Midland Wolfcamp

AVG Lat Length (ft) 4,398 ~6,700 5,619 5,137 AVG Lat Length (ft) 7,168 7,366 7,555 ~8,200 8,273 8,071

*Operators Include: Advanced Pet, Bopco, Bta Oil Producers, CVX, CXO, Caza, CDEV, DVN, EOG, LGCY, MRO, MTDR, Mcelvain O&G, Mewbourne, Murchison, WPX, XEC, XOM

*Operators Include: APC, BHP, CRZO, CVX, CXO, CDEV, EGN, EOG, FANG, HK, Jagged Peak Energy, Mewbourne, MTDR, NBL, RDSA, REN, RSPP, WPX, XEC

*Operators Include: APA, Broad Oak, CPE, CVX, CXO, Crownquest, ECA, EGN, END, EPE, FANG, LPI, PE, PXD, SM, Sem Opg, Surge Opg, XOM

*Operators Include: COP, CXO, CDEV, Caza, DVN, EOG, MRO, MTDR, Mewbourne, WPX, XEC

51

5 7 7

231619 21

22

21

2628

45

1Q17A 2Q17A 3Q17A 4Q17A 1Q18E 2Q18E

Optimized Development PlansOperational resources secured and on-board for 2018

• Added 4 drilling rigs end of 2Q17

• Added 4th frac crew in 3Q17

• Added additional flowback and hookup resources in 4Q17

1H 2017 = ~7,000 ft 2H 2017 = ~7,800 ft 1H 2018 = ~8,500 ft

Texas

New Mexico

Record Well Results Provide Near-term Visibility to Achieving 80 Mboed Production Increase Milestone

34 - 38

59 - 63

1Q18 well counts reflect updated sequencing for optimized pad development

Permian Resources Horizontal Wells Online

Actual Outlook

Average Lateral:

52

• Pipe Yard has 16 rail car spots• 50,000 tons of storage• Pipe from rail line instead of trucked

from Houston• 24-hour access with the ability to

service more than 20 rigs

Dedicated personnel, services and equipment:• Directional drilling• Cementing• Fracturing• Wellhead and frac tree systems

• Northern white sand supply• Regional sand supply • Sand mine to Aventine logistics

• Sand transloading terminal operations• Sand last mile logistics and wellsite

storage provider

- Service Provider Facility

- Sand Provider

- Facility Operator

- OCTG

Project Aventine – Strategic Partnerships Reduce Costs in Value Chain

• HCl facility has 14 rail car spots• OxyChem is the HCl provider

Project Aventine

• 240 acres in Eddy County, NM within 20 miles of Greater Sand Dunes and other future development areas

• 30,000 tons of sand storage + transload capacity

• 2 unit train loops with ability to expand to 3 located off major rail line

• Supports 10-12 rigs per year

• Reduces costs by $500 - $750 k per well• Secures availability of critical materials• Reduces spare equipment and personnel needed on location• Reduction in last mile logistics cost• Dedicated equipment maintenance facilities• Savings start 1Q18, fully operational 2Q18• Phase 2 will support production operations HCl Provider

Mutually Beneficial Partnerships Reduce Costs

52

HCl Facility

53

New D&C Records

$0

$2

$4

$6

$8

$10

$12

4Q17 Actual Market Inflation Aventine LogisticsSavings

Design/EfficiencyImprovements

2018 Target

Wel

l Cos

t ($

MM

)

Drilling Completion Hookup

New Mexico Well Cost Improvements

• Well design: fluid optimization and produced water recycling

• Logistics: Project Aventine

• Operating: reduced TTM

Breakeven Plan Sustainability Enhanced by Operating Efficiency and Logistics Savings

New Mexico 2nd Bone Spring 10,000’ Well Cost

$8.9 MM

$0.6 MM $0.8 MM

$0.8 MM$9.9MM

Drilled Jan 2018 Corral Fly 02-01 State 23H2nd Bone Spring – 9,800’

15.8 days Drilling9,701ft lateral – 44 hrs

5,689ft of lateral in 24 hrs1st 10k-ft w/ 5-1/2” floated casing

14 stages / dayCompleted Jan 2018

Cedar Canyon 29 Fed 24H, 25H, and 26H2nd Bone Spring – 4,700’

• Reduction in sand related costs> Direct sourcing> Last mile logistics> Well-site logistics

• Less redundancy in well-site equipment and supervision

• Reduced HCl costs

Note: Well costs include, drilling, completion, hookup, flowback, 1st artificial lift, and capitalized overhead. Well design assumes 3-string casing with 2,000#/ft completion

54

$12.93

$11.17

$8.43$8.00

$7.63

$-

$4.00

$8.00

$12.00

2014 2015 2016 2017 2017 Q4

Permian Resources Opex/BOE

Surface Downhole Supports Energy Other

Operating Capability Reduces Costs

• Water-handling reducing surface costs

• Lift optimization reducing downhole failure costs

55

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Breakeven <$50

Breakeven <$60

Breakeven <$70

AdditionalInventory

4Q17 Normalizedto 7,100'

4Q16

Added ~30 Rig Years of Activity to <$50 Inventory in 2017

3,132

4,771

5,637

11,20711,650

Permian Resources Inventory 2Q17

> Added 750 locations BE <$50

• ~500 in New Mexico

• Replaced majority of inventory from divestitures

• Divestiture impact to locations >$50 only

> Added 3.0 MM ft of horizontal lateral footage to inventory

• Increased average length from 7,100 ft to 7,600 ft

Midland Basin

Texas Delaware

Basin

New Mexico Delaware

Basin

Note: Breakeven defined as positive NPV 10.*As of 12/31/2017. 4Q 2017 increased lateral length adjustment to normalize current inventory to 7,100’.

11,996*

Und

evel

oped

Dril

ling

Loca

tions

56

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 ZoneNote: As of 12/31/2017

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

Permian EOR CO2 Floods

Permian EOR PlantsTotal

Identified Barrels

57

Permian Resources• Significant growth potential in

all development areas

• ~650,000 net acres within the Delaware and Midland Basin boundaries

• NM Delaware Basin 290,000

• TX Delaware Basin 160,000

• Midland Basin 200,000

Total ~650,000

NetAcres*

Resources Basin Development Areas

• Central Basin Platform 260,000

• New Mexico NW Shelf 150,000

• Continuing Evaluation 340,000

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.Note: As of 12/31/2017

• ~325,000 net acres associated with 11,207 wells in unconventional development inventory

• Additional acreage evaluated in 2017 offset by divested acreage

58

Appendix Contents


• 2017 Reserves

• Permian Updates


59

Chemicals Cash Flow Improvement Drivers

JV Ethylene Cracker startup complete

4CPe Plant startup in 4Q17 with ramp through 1H18

Capturing margin from improving pricing and operations

Annualized Chemicals Cash Flow From Operations ($ MM)

0

200

400

600

800

1,000

1,200

1,400

1,600

1Q17CFFO Annualized

Ethylene CrackerStartup

Market Improvement 4CPe PlantRamp-up

Breakeven PlanTarget

$1,475

$150$1,125

$50

$150

Achieved

60

Chemicals Free Cash to Significantly Increase with Lower Capital Spending

• 4CPe Plant complete on-time and on-budget> Plant started up in 4Q17

• 4CPe Plant manufactures the feedstock for a climate-friendly, next generation refrigerant to be used in automobiles> Feedstock to be provided to new, world-scale plant in Baton Rouge for

production of 1234YF (next generation refrigerant)

• OxyChem capital spend will be near maintenance levels in 2018

0

100

200

300

400

500

600

700

2011 2012 2013 2014 2015 2016 2017

Maintenance & Other Spending New Business Spending

$m

m

Chemicals Capital Spend

4CPe Plant

61

Market Overview Update

• Major industry consolidation complete

• Caustic soda supply-demand balance continues to improve

• PVC demand improved YoY

0

50

100

150

200

250

300

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

E

$ M

illio

ns

Chemicals Pre-Tax Earnings (EBIT)1

0.000.501.001.502.002.503.003.504.004.505.00

0

100

200

300

400

500

600

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

$/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

62

Midstream Cash Flow Improvement Drivers

Al Hosn plant continued optimization: 1Q 2018

Oil terminal capacity upgrade: 2H18 – 2019

Near-term Midland to Gulf Coast spread outlook ~$2.50

Annualized Midstream Cash Flow From Operations ($ MM)

0

50

100

150

200

250

300

350

400

450

500

1Q17CFFO Annualized

Marketing Spread QuarterlyAverage >$2.10 per Boe

Al Hosn GasPlant Optimization

Crude Oil Terminal CapacityUpgrade

Breakeven Plan Target

$450

$200

$150

$50

$50

Achieved

Downtime Adj.

$50 Actual

Notes:1 Excludes non-cash impacts of mark-to-market on crude contracts. 2 $50 MM improvement due to Al Hosn expansion is $20 MM allocated to midstream and $30 MM allocated to upstream.

1 2

63

Near-term Outlook for Midland to Gulf Coast Spreads

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

Midland to Magellan East Houston Spread ($/bbl)

Actual Outlook

Harvey Impact on

Spread

2018

1Q 2Q 3Q 4Q

2017

1Q 2Q 3Q 4Q

2019

1Q 2Q 3Q 4Q

Upper Bound

Lower Bound

New Pipeline Capacity

Breakeven Plan Assumption: $2.10

Accelerating global economic growth drives strong demand

Balanced global supply assuming OPEC+ extension

Permian pipeline utilization ~85-90% over time

Possible pipeline capacity constraints pending newproject in-service dates (late 2018/early 2019)

64

Leadership in Gulf Coast Crude Exports

Increasing Ingleside export capacity to 750,000 bopd

Oxy Ingleside – The Premier Crude Export Terminal> Expansion underway for VLCC loading arms, tankage and piping> Increasing capacity 2.5x to 750,000 bopd with 6.8 MMbbls of storage> ~$315mm total capital with ~$115mm spent in 2018> New Permian pipeline supply anticipated 2H19

2H

18

-2

019

VLCC

Suezmax

> Expanding Ingleside Terminal• VLCC loading capability 4Q18• Capacity increase 2H19

> Leading Permian Crude Marketer with ~600,000 bopd

> Largest Permian crude exporter

Ingleside Oil Terminal

occidental petroleum corporation february 14, 2018...4q17 results *see significant items affecting...

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