Occidental Petroleum Corporation November 2, 2017€¦ · marketing spreads of $2.61/Boe during 3Q...

November 2, 2017Occidental Petroleum Corporation

Third 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

Richard A. JacksonVice President ‐ Investor Relations

713‐215‐7235 | [email protected]

Anthony J. CottoneSenior Director ‐ Investor Relations

713‐552‐8678 | [email protected]

4

Occidental Petroleum

• Pathway to Breakeven Progress

• Financial Summary and Guidance

• Permian Resources Update

• Closing Remarks

5

Impact of Hurricane Harvey for 3Q17Pre-Tax Income Loss – ~$70 MM

• Chemicals $60 MM

• Midstream $10 MM

• Permian Resources production loss of 1 Mboed

Hurricane Harvey impacts are expected to affect only 3Q17

6

Occidental Petroleum Pathway to Breakeven and 3Q17 Highlights

> Increased Seminole San Andres CO2 unit gross production 2,300 Boed since gaining operatorship

> Record 270 Mbod exported from Ingleside terminal in September

> Captured value through improved domestic marketing spreads of $2.61/Boe during 3Q

Operations and Technological Progress

Value-based Development ApproachPortfolio Management

> $1.8 Bn 3Q17 cash balance> Received first cash

distribution from Ingleside Ethylene JV cracker

> Traded 13,000 net Permian Resources acres YTD to enable longer laterals and consolidated facilities

> Brent premium improves crude export margin and international cash flow

*Note: Three stream production results.

> Record Permian Basin wells across multiple benches*

• Five NM 3rd Bone Spring wells with average 30D rates 3,780 Boed

• One NM 2nd Bone Spring well with 30D rate of 4,500 Boed

• One NM Wolfcamp XY well with 30D rate of 2,800 Boed

• Additional company well productivity records in TX Delaware Wolfcamp B and 2nd Bone Spring

> Permian operating cost reductions• Permian Resources YoY improvement

of 7% to $7.61/Boe

Permian Resources Achieves Record Well Results Across Multiple Development Areas and Benches

7

0.0

1.0

2.0

3.0

4.0

5.0

6.0

3Q17 AnnualizedCFFO Adjusted to

$40 WTI

Chemicals Midstream &Marketing

70 MboedPermian

ResourcesProduction

OtherImprovements

Cash Flow Neutralat $40 WTI

Increase in CashFlow at $50 WTI

Cash FlowBreakeven with

5%-8% Growth at$50 WTI

$3.5

$3.8 $3.9$4.5 $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 Market

Pathway to Cash Flow Breakeven at Low Oil Prices

$4.5

Harvey Impact$3.7

8

$0.2

$0.3

$0.7

$0.2

0.0

0.2

0.4

0.6

0.8

Chemicals Midstream Permian Resources Production

Achieving Goals to Cash Flow Neutrality at $40Harvey impacted Chemicals cash flow by $160 MM annualized and Midstream cash flow by $30 MM annualized

Ethylene cracker distributed first dividend in 3Q17

Marketing differential was improved sequentially

Added 1 Mboed of Permian Resources production after divesting ~5 Mboed on August 1

Other Improvements

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

Seminole San Andres Synergy Value

Remaining

Chemicals ~$10/ton Caustic Soda Realizations

Remaining

4CPE Plant Remaining

Al Hosn Optimization and Crude Terminal Capacity Upgrade

Remaining

70 Mboed Growth

Remaining

9

Ample Liquidity to Fulfill Plan Even at $40 WTICash flow outspend through the completion of our plan is covered by available liquidity, including:• Current cash balance: $1.8 Bn• Portfolio management: $0.5 - $2.0 Bn• PAGP units: $0.6 Bn• Undrawn revolving credit facility: $2.0

BnWe do not anticipate increasing debt levels to achieve plan

(4.0)

(3.0)

(2.0)

(1.0)

-

1.0

2.0

3.0

4.0

5.0

6.0

OperatingCash Flow

Dividends CapitalExpenditures

AvailableLiquidity

Cash Flows Through End of 2018 at $40 WTI

Remaining 2017

2018

Cash Balance

PAGP

Portfolio Management

Cash Flow Deficit

$B

n

$3.6 -$3.9 Bn

At $50 WTI, liquidity to fund the plan is forecasted to be less than $200 MM

after use of cash

10





• Closing Remarks

11

Results600,000

139,000

$0.25

$0.18

$1.1 Bn

$0.9 Bn

$1.8 Bn

Total reported production (boed)

Total Permian Resources production (boed)

Reported diluted EPS

Core diluted EPS*

3Q17 CFFO before working capital & other

3Q17 capital expenditures

Cash balance as of 9/30/2017

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

3Q 2017 Results

12

Beginning CashBalance1/1/17

CFFO BeforeWorking Capital

Change inWorking Capital

CapitalExpenditures

Dividends Asset Sales Acquisitions/Other

Tax Refund Ending CashBalance9/30/17

YTD 2017 Cash Flow and Cash Balance Reconciliation

$1.8

($1.8)

$3.2

$2.2

($2.5)($0.3)

($ in Bn)

$1.3$0.8

($1.1)

13

Oil & Gas Segment • FY 2017E Production

> Total production of 597,000 – 599,000 boed

> Permian Resources production of 141,000 – 144,000 boed

• 4Q17E Production

> Total Production of 633,000 – 641,000 boed

> Permian Resources production of 156,000 – 170,000 boed

Production Costs – FY 2017E

• Domestic Oil & Gas: ~$13.50/ boe

Exploration Expense

• ~$35 MM in 4Q17E

DD&A – FY 2017E

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

Midstream

• $60– $80 MM pre-tax income in 4Q17E

Chemical Segment

• ~$190 MM pre-tax income in 4Q17E

Corporate

• FY 2017E Domestic tax rate: 36% • FY 2017E Int'l tax rate: 55%• Interest expense of $85 MM in 4Q17E

4Q17 and FY 2017 Guidance Summary

14





• Closing Remarks

15

-

50

100

150

200

250

0 30 60 90 120 150 180

3rd Bone Spring Performance

-

50

100

150

200

250

0 30 60 90 120 150 180

2nd Bone Spring Performance

Wolfcamp XY

Sustainable, Step Change in Well Results De-risks Breakeven Plan

CC

23

FED

CO

M 0

33

H –

7,2

00

ft

CC

21

22

FED

CO

M 0

34

H –

9,8

00

ft

CC

21

22

FED

CO

M 0

33

H –

9,8

00

ft

CC

23

24

FED

03

1H

–7

,20

0 f

t

CC

23

24

FED

CO

M 0

34

H –

7,2

00

ft

CC

23

24

FED

03

2H

–7

,20

0 f

t

CC

23

FED

CO

M 0

06

H –

7,2

00

ft

0

1,000

2,000

3,000

4,000

5,000

2,805

3,4643,672

3,563

3,824

4,3794,503

3Q17 Record Well Results in Greater Sand Dunes

Notes: 1Three stream production results. 2For top wells in basin, data is based on IHS calendar month production through August 30, 2017,and Oxy data is internal calendar month production.

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

Last 7 wells brought online in Greater Sand Dunes with 30D production rates averaging 3,750 Boed

Placed 3 wells on production with 30D rates in the top 15 in the entire basin2

Record well results are across multiple flow units

Confident in sustainable performance with locations in excess of2,000 in the GreaterSand Dunes

2nd Bone Spring

3Q17 Wells – Peak 30D Production Rates1

Cum

ulat

ive

Prod

uctio

n (M

boe)

Days Online3rd Bone Spring

3Q17 Well

3Q17 Wells

16

Recent Rig AdditionsBegin Contributing to Production Growth Greater Sand Dunes rig count increased from 2 rigs in 1Q17 to 5 rigs in 3Q17. Expect to increase to 6-7 rigs in 1Q18

New Mexico wells online will increase by ~5x from 1Q17 to 2Q18E

Value-based development

• Subsurface characterization• Customized landing and

completions• Pad Drilling Increasing• Lateral Length Increasing 5 7 7

20 202616

19 21

22 2419

21

2628

4244 45

1Q17A 2Q17A 3Q17A 4Q17E 1Q18E 2Q18E

Permian Resources Horizontal Wells Online

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

TexasNew Mexico

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

17





• Closing Remarks

Appendix

19

Appendix Contents

• Permian Updates

• Midstream and Chemicals Updates

• Social Responsibility, Environment, and Governance

• Journey to Digital Transformation

• Company Overview and Value Proposition

20

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.

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 4,937 4,871 ~6,000 5,196

New Mexico Bone Spring

New Mexico Wolfcamp

Texas Delaware Wolfcamp

Texas Midland Wolfcamp

0

50

100

150

200

250

2015 1H 16 2H 16 2017 Target Top Peers2016

AVG Lat Length (ft) 4,398 ~6,700 5,092 AVG Lat Length (ft) 6,700 7,457 7,467 ~8,200 8,101

AVG Lat Length (ft) 4,807 5,418 7,758 ~7,500 6,097

0

50

100

150


0

50

100

150

200


020406080

100120


*Operators Include: Bopco, Bta Oil Producers, CHI, CVX, CXO, Caza, CDEV, DVN, EOG, Fasken Oil And Ranch, LGCY, MTDR, Marshall & Winston, Mcelvain O&G, Mewbourne, Regeneration Energy, WPX, XEC, XOM

*Operators Include: APA, APC, BHP, COP, CRZO, CVX, CXO, CDEV, EOG, FANG, HK, JAG, MTDR, Mewbourne, NBL, PDCE, RDSA, REN, RSPP, WPX, XEC, XOM

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

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

21

139

110

124 123 129

138

139

2015 2016 Q4 2016 1Q17 2Q17 3Q17 4Q17E 2017E

141-144

156-170

143*

• Resources production grew 1% from Q2 17 to 139 Mboed after divestment and Harvey

> Divested assets: -3 Mboed 3Q impact

> Hurricane Harvey: -1 Mboepd 3Q impact

• Significant production growth occurring in 4Q17 and 2018+

> Impact of 4 rigs added mid-2017

> Shift to more New Mexico activity

> Improving well results provides additional upside

Permian Resources Results and Guidance

*Q3 production total without impact of Hurricane Harvey and including the production divested from the Midland Basin

22

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

Low case rig count* High Case rig count*

6

8

8 8

131413 rigs at exit

2017 Exit rig count*

Current trajectory of 30% CAGR 2017 - 2019

• Significant increase in 4Q17 wells online> 11 operated rigs, 6-7 in Greater

Sand Dunes by 1Q18> 2017 Capex coming in at mid-

point of capital range of $ 1.6 -$1.8 Bn

• 2018 program on track for above 30% growth

Achieving Plan Through Value-based Approach

*Includes estimated net non-operated rigs

23

$12.93

$11.17

$8.43$8.14

$-

$4

$8

$12

2014 2015 2016 2017 YTD

Permian Resources Opex/BOE

Surface Downhole Supports Energy Other

Operating Capability Reduces Costs

• Water-handling improvement reducing surface costs

• Continued lift optimization reducing downhole failure costs

• Operating efficiencies offsetting cost inflation

• High-margin production growth

Continued Margin Improvement Through Opex Reduction

24

0

50

100

150

200

250

0 30 60 90 120 150 180

Cum

ulat

ive

MB

OE

Days Online

Value-Based Development Increases ReturnsGreater Sand Dunes

1H17 – 11 wells5,650 Avg. Lat. Length

2016 - 14 wells5,350 Avg. Lat. Length

Well Performance ImprovementsAverage 2nd Bone Spring, 3rd Bone Spring and Wolfcamp X/Y

3Q17 – 7 wells8,000 Avg. Lat. Length

• Continued play-leading results from three benches> 2nd Bone Spring

> 3rd Bone Spring

> Wolfcamp X/Y

• Vision well design process drives improvements

• Improved performance in 3Q from landing and frac optimization

> 45 % improvement in Q3 performance over 1H17

2nd Bone Spring Landing and Frac Optimization

Play-leading Well Performance

25

-

50

100

150

200

250

300

350

- 30 60 90 120 150 180

Cum

MB

OE

Days Online

$4.95 $3.43 $3.50

$2.62

$9.41

$-

$2

$4

$6

$8

$10

Red Bull South Mentone Lockridge Barilla - Birds of PreyArea

Tx Delaware - TotalOperated Fields

20

17

YTD

–O

pex

/ B

OE

Greater Barilla DrawOperating Excellence & Strong Results 2017 Barilla Draw proper– Wolfcamp A Optimized Landing Point Results

Value-Based Development Increases Returns

Lyda 16H– 10,150’

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

Average of 201710,000 ft wells (3)

Average of 20175,000 ft wells (3)

• Oxy record wells in Texas Delaware in 2 new benches> 2nd Bone Spring

> Wolfcamp B

• Barilla Draw wells continue to improve> 2017 5,000 ft wells ~70% above previous

performance

> 2017 10,000 ft wells ~170% above previous performance

• Horizontal development continues to improve margins> Four fields with primarily horizontal wells

have sub $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: 52 11 11 18

Avg. Hz well age: ~2 years ~ 2 years ~1.5 years ~2 years

26

Midland Basin - Merchant

• Operating cost <$3/boe> Horizontal only development

> 10,000 ft wells go-forward

> Infrastructure designed for full-field development

• Two play-leading benches under development> Landing point optimization

> Wolfcamp B performance +45%

• Full-field planning success being leveraged for similar future Midland Basin multi-bench development

Wolfcamp B Improvement = two high-return development benches

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

Value-Based Development Increases Returns

$2.84

$-

$1

$2

$3

2017 YTD

Downhole Maint Surface Other

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

-

20

40

60

80

100

120

140

160

180

- 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

Mature Field with High Margins

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

2nd BSS

Cedar Canyon 23 Fed Com 6H 7,241 4,518 3,963 84%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 Total 2017 Average 5,617 2,568 2,195 81%

3rd BSS

Cedar Canyon 23-24 Fed 32H 7,235 6,497 3,728 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 3,050 71%Cedar Canyon 23-24 Fed 31H 7,228 5,152 3,041 67%Cedar Canyon 21 22 Fed Com 33H 9,758 3,730 3,178 75%Oxy Total 2017 Average 7,381 3,974 2,846 74%

Wolfcamp XY

Cedar Canyon 23 Fed Com 33H 7,228 2,898 2,460 75%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 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%

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 3Q17. All BOE Data is based on two-stream well testsAverage 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-Y

Wolfcamp A

Wolfcamp D

6,0

00

ft

New

New

New

28

Target Formation

Recent Well Results

Well NameLateral Length

(ft)Peak 24 Hr

(boed)Peak 30 Day

(boed)Oil (%)

Avalon Evaluating

1st BS Evaluating

2nd BSCollie A East N63H 9,725 1,370 1,155 84%

Aardvark State 6 2H 4,947 1,254 821 87%

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

3rd BSMorrison, HB 73H 4,927 962 864 75%

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

Wolfcamp A

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%

Buzzard State Unit #16H 7,700 2,050 1,822 74%

Peck State 258 #6H 4,212 2,244 1,791 82%

Toyah 4 9 2N 12H 9,890 2,069 1,672 83%Oxy Total 2017 Average 7,394 1,888 1,517 74%

Wolfcamp DF

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

Oppenheimer 188 2H 4,776 1,547 1,340 82%

Teller 186 1H 4,681 1,707 1,263 81%

Nyala Unit 9B #3H 6,575 1,535 1,247 83%

Wolfcamp B

Agate 179-142-3S 25H 7,439 2,088 1,611 70%

Manhattan 183W 1H 7,092 1,954 1,584 75%

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

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

Oxy Total 2017 Average 7,350 1,571 1,244 78%

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 3Q17. All BOE Data is based on two-stream well tests.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 A

Wolfcamp DF

Wolfcamp C

4,5

00

ft

Wolfcamp B

New

New

New

New

29Note: Slide last updated 2Q17

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

30

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

Note: Breakeven defined as positive NPV 10. Slide last updated 2Q17

Und

evel

oped

Dril

ling

Loca

tions 45

155 45100

100

31

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. Last updated 2Q17

11,963*

Und

evel

oped

Dril

ling

Loca

tions

32

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

33

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

34*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

35

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

36

Oxy’s Competitive Advantage in Permian Unconventional

Subsurface Characterization

3D Modular Development

Development Scenarios

Vision Well Manufacturing Blueprint

Portfolio Decisions

Hands-Free Operations

Leadership in Full Cycle Returns

Automation and Data CaptureSystem Integration

Data Analytics

Organization Designed for Integrated Development

Valu

e B

ased

Tech

nolo

gy +

Dev

elop

men

t Sys

tem

Inno

vatio

n

37

Subsurface Characterization Adds Value• Extensive subsurface

characterization & expertise> Seismic integration

> Data acquisition

> Models

• Customized designs based on unique subsurface attributes> Sweet spots

> Frac barriers

> Landing zones

• Capture resource potential at the highest value

Schematic Representation of 2nd Bone Spring Sand Well Placement

2nd Bone Spring Net Sand Thickness and Middle Carbonate Outline

Seismic Interpretation of Middle Carbonate Inside 2nd Bone Spring Sand

A

A A’

Landing + Stimulation + Spacing Optimization

A A’

A’Middle Carb. Outline

38

Production drivers

Data analytics

Implement

Surveillance

Vision Well

Design the system

Challenging the Vision Well Adds Value

• Discover recipe for play-leading wells

• Apply data analytics to identify production drivers> Subsurface

> Completion Design

> Choke and lift optimization

• Design the system to test hypothesis

• Implement and confirm results

• Continue to push expectations

39

Modular Development Adds Value• Maximize value through optimizing

pace and sequencing

• Identify Uncertainties: > Variability of production results

> Rate of improvement

• Recognize Current Limitations> Existing infrastructure capacity and water

network

> Land position

• Realize full cycle returns through modular field development plans

1

2

3

44

Land core-up completedLearnings from other development

units appliedVision wells maximizing value Infrastructure optimized

40

Permian EOR Water Floods Permian EOR CO2 Floods

Permian EOR Plants

Permian EOR• 146 Mboed net production*

• 1.1 MM net acres

• ~20k operated wells

• 34 CO2 floods

• 70 water floods

• 13 gas processing plants

• 3 operated CO2 source fields

• 2.4 Bcf injected daily

Over 2 Bboe Net Resource Potential~1 Bboe at <$6 F&D

Differentiated Scale and Position

* 2Q 2017 Net Production; does not include Seminole San Andres Acquisition

41

Unmatched Infrastructure PositionField

• ~20,000 wells

• 1,200+ surface facilities

• 30,000 miles of pipelines

• 230+ pumps for water reinjection

Plants

• 13 gas processing plants

• 9 recompression facilities

• 920k hp compression

• 1,600 miles of gathering pipelines

• 1,100 miles of DOT pipelines

• Long-term CO2 supply agreements

Integrated Communications

• Microwave backbone across Permian Basin

42

Permian EOR Keys to Success: Long-term Life Cycle

• Technical EOR Expertise

• Infrastructure and CO2 Supply

• Gas Processing

• Automation and Controls

• High-quality Reservoirs

• Contiguous Scale

• Strategic Position

• 1 Bboe < $6/boe F&D

• Subsurface Characterization

• Phased Development Cycles

• Surveillance and Maintenance

• Safety and Environmental

• Centralized Control of Field and Plants

• Data Automation and Capture

• Data Analytics

• Hands-free Operations

43

Benefits of EOR Business Unit in Oxy’s Portfolio

• Long-term cash generator> Low capital intensity

growth opportunities

> Less than 5% base decline

• Provides synergies including organizational capabilities across business units

Recovery of Oil in Place*

Proven History of Maximizing Recovery

Rec

over

y Fa

ctor

(%)

Reservoir Development Stages

0%

10%

20%

30%

40%

50%

60%

70%

Conventional Reservoirs UnconventionalReservoirs

Primary

Waterflood

CO2

BO

PD

Low Base Decline Generates Sustainable FCF

Primary~15%

Waterflood~30%

CO2~15%

*Recovery factors listed are representative and are not specific to a field. Actual recovery factors will vary higher and lower depending on specific reservoir characteristics.

Primary~6-12%

44

Permian EOR Maintenance

• 20,000 maintenance activities per month supported by:

> “Right-sized” programs

> Computerized Management System

> Total cost life-cycle approach

Value-based, Full Cycle Approach

Annual Beam Unit Reliability

Drone and Infrared Camera Inspections

99.6% 99.7% 99.8% 99.8% 99.9%

2013 2014 2015 2016 2017

Safer Faster Cheaper Effective

Detect Solids in TanksDetect Hot Spots at Plants

Less than 20 of 7,000+

Beam Units Fail Each Year

45

Appendix Contents

• Permian Updates


• Social Responsibility, Environmental, and Governance



46Notes:1 Excludes non-cash impacts of mark-to-market on crude contracts. 2 Other Midstream includes seasonality in the domestic pipeline, power generation, gas marketing businesses and other improvements in international, inventory and other marketing. 3 $50 MM improvement due to Al Hosn expansion is $20 MM allocated to midstream and $30 MM allocated to upstream.

Annualized Midstream Cash Flow From Operations ($ MM)

0

100

200

300

400

500

600

700

1Q17CFFO

Annualized

DomesticCrude

MarketingSpread

OtherMidstream

Harvey After-Tax Impact

3Q17CFFO

Annualized

OtherMidstreamSeasonality

Normalized to$2.10 Outlook

MarketingSpread

Plains UnitDistributionReduction

Al HosnOptimizationand Crude Oil

TerminalCapacityUpgrade

BreakevenPlan Target

$30

$500

Midstream and Marketing Cash Flow Improvement Drivers

Al Hosn plant continued optimization: 2018

Oil terminal capacity upgrade: 2H18 – 2019

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

$100

$660

1Q17 Actual$50

$290

$190

Crude marketing spread improvement has

exceeded expectations of $200 MM

$450 MM Breakeven Plan Target$300 MM Improvements:

- $200 MM Marketing Spread- $100 MM: Al Hosn Optimization

and Crude Terminal Capacity Upgrade1Q17

Adjustments for Downtime

$150

$510 Improvement Since 1Q17

($140)

($30)

Actual Forecast

($90)

1 132

$50 MM of upside not currently included in

breakeven plan

47

0.00

1.00

2.00

3.00

4.00

5.00

6.00

Midland to Magellan East Houston Spread ($/bbl)Near-term Outlook for Midland to Gulf Coast Spreads 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

Global refining margins expected to remain strong

Global crude oil supply will be balanced assuming OPEC extension

Permian pipeline utilization ~85-90%

New Pipeline Capacity

Breakeven Plan Assumption: $2.10

48

A Leader in Crude Exports from the Gulf CoastPremier oil terminal on the Gulf Coast

Leading Permian Crude Marketer with ~600,000 bopd

Largest US Gulf Coast light crude exporter

Opening new markets in China, India, S Korea and SE Asia

0

200

400

600

800

1,000

Jan-

16

Feb-

16

Mar

-16

Apr-1

6

May

-16

Jun-

16

Jul-1

6

Aug-

16

Sep-

16

Oct

-16

Nov

-16

Dec

-16

Jan-

17

Feb-

17

Mar

-17

Apr-1

7

May

-17

Jun-

17

Jul-1

7

Aug-

17

Sep-

17

Mbo

d

Oxy Share of US Gulf Coast Light Crude ExportsOXY Light Other Exporters Light

Export Ban Lifted

Oxy Ingleside Startup

49

Annualized Chemicals Cash Flow From Operations ($ MM)

0

200

400

600

800

1,000

1,200

1,400

1,600

1Q17CFFO

Annualized

EthyleneCracker Startup

Market andOperations

Improvement

Harvey After-Tax Impact

3Q17CFFO

Annualized

Market andOperationsSeasonality

4CPe Plant MarketImprovement

Breakeven PlanTarget

$1,475

Chemicals Cash Flow Improvement Drivers

JV Ethylene Cracker startup complete

4CPe Plant startup: 4Q17

Capturing margin from improving pricing and operations

$40$150

$1,125

$1,475 $30($80)$160

$350Improvement Since 1Q17

$1,475 MM Breakeven Plan Target$350 MM Improvements:

- $150: Ethylene Cracker Startup- $50: 4CPe Plant Startup- $150: Market Improvement

Actual Forecast

$50

50

• 4CPe Plant commercial operation expected in 4Q 2017> Project is mechanically complete, on schedule and below budget of $147

MM

> The plant is currently being commissioned

• 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 continue to decline in 2017 and be near maintenance levels in 2018

0

100

200

300

400

500

600

700

2011 2012 2013 2014 2015 2016 2017E

Maintenance & Other Spending New Business Spending

$m

mChemicals Free Cash Flow to Significantly Increase with Lower Capital Spending

4CPe Plant during construction –Construction complete and undergoing commissioning

Chemicals Capital Spend

51

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

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

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

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

$/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

52

Appendix Contents

• Permian Updates

• Midstream and Chemicals

• Social Responsibility, Environmental, and Governance



53

Reporting on Social Responsibility Since 1995

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

•

54

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 and opportunities

> 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

55

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

56

5%

63%

Fresh Water

Brackish Water

Recycled Water

32%

$3.50

$2.10

$0.75

$-

$1

$2

$3

$4

Original Improved Current

Cost

/ b

bl o

f wat

er

Produced Water Costs Completion Water Costs Water Recycling

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

2017 Delaware Basin YTD Completion 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 Completion

Water

Pipe Produced Water+ Truck Completion

Water

Recycle Produced Water for Completion Water

$1.50

$2.00$1.50

$0.60

Industry-Leading Water Recycling Program

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

• Sand Dunes Water Recycling Project> 80% of water used in completions 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

57

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

58

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)

59

Appendix Contents

• Permian Updates





60

• 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

61

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

62

• 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

63

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)

64

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

65

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

66

Appendix Contents

• Permian Updates





67

$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

67Note: 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%

68

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

69

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

70*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

71

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

72

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.

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