Third Quarter 2017 Earnings Conference Call. Occidental Petroleum Corporation November 2, 2017

Transcription

1 Third Quarter 2017 Earnings Conference Call Occidental Petroleum Corporation November 2, 2017

2 Cautionary Statements Forward-Looking Statements Portions 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 Information This presentation includes non-gaap financial measures. You can find the reconciliations to comparable GAAP financial measures on the Investors section of our website. 2

3 Richard A. Jackson Vice President Investor Relations Anthony J. Cottone Senior Director Investor Relations

4 Occidental Petroleum Pathway to Breakeven Progress Financial Summary and Guidance Permian Resources Update Closing Remarks 4

5 Impact of Hurricane Harvey for 3Q17 Pre-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 5

6 Occidental Petroleum Pathway to Breakeven and 3Q17 Highlights Permian Resources Achieves Record Well Results Across Multiple Development Areas and Benches Portfolio 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 Value-based Development Approach > Record Permian Basin wells across multiple benches* Five NM 3 rd Bone Spring wells with average 30D rates 3,780 Boed One NM 2 nd 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 2 nd Bone Spring > Permian operating cost reductions Permian Resources YoY improvement of 7% to $7.61/Boe Operations and Technological Progress > Increased Seminole San Andres CO 2 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 *Note: Three stream production results. 6

7 Pathway to Cash Flow Breakeven at Low Oil Prices Operating Cash Flow ($ Bn) Cash Flow Breakeven at $50: Dividend + 5% 8% Production Growth $5.7 $5.7 Cash Flow Neutral at $40: Dividend with Flat Production $3.7 Harvey Impact $3.5 $3.8 $3.9 $4.5 $4.5 Seminole-San Andres Acquisition + Chemicals Market $4.5 Sustaining Capital $2.1 Current Dividend $2.4 $120 MM per $1 Change in WTI Growth Capital $1.0 Sustaining Capital $2.3 Current Dividend $ Q17 Annualized CFFO Adjusted to $40 WTI Chemicals Midstream & Marketing 70 Mboed Permian Resources Production Other Improvements Cash Flow Neutral at $40 WTI Increase in Cash Flow at $50 WTI Cash Flow Breakeven with 5%-8% Growth at $50 WTI 7

8 Achieving Goals to Cash Flow Neutrality at $40 Harvey impacted Chemicals cash flow by $160 MM annualized and Midstream cash flow by $30 MM annualized Ethylene cracker distributed first dividend in 3Q17 Marketing differential was improved sequentially Added 1 Mboed of Permian Resources production after divesting ~5 Mboed on August Annualized Cash Flow From Operations Improvements ($ Bn) 4CPE Plant Remaining $0.2 Achieved since 1Q17 Al Hosn Optimization and Crude Terminal Capacity Upgrade Remaining $0.3 Breakeven Plan 70 Mboed Growth Remaining $0.7 Seminole San Andres Synergy Value Remaining Chemicals ~$10/ton Caustic Soda Realizations Remaining $ Chemicals Midstream Permian Resources Production Other Improvements 8

9 Ample Liquidity to Fulfill Plan Even at $40 WTI Cash flow outspend through the completion of our plan is covered by available liquidity, including: Current cash balance: $1.8 Bn Portfolio management: $0.5 - $2.0 Bn PAGP units: $0.6 Bn Undrawn revolving credit facility: $2.0 Bn We do not anticipate increasing debt levels to achieve plan At $50 WTI, liquidity to fund the plan is forecasted to be less than $200 MM after use of cash $Bn (1.0) (2.0) (3.0) (4.0) Cash Flows Through End of 2018 at $40 WTI Operating Cash Flow Cash Flow Deficit Dividends $3.6 - $3.9 Bn Capital Expenditures 2018 Remaining 2017 Portfolio Management PAGP Cash Balance Available Liquidity 9

10 Occidental Petroleum Pathway to Breakeven Progress Financial Summary and Guidance Permian Resources Update Closing Remarks 10

11 3Q 2017 Results 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 Results 600, ,000 $0.25 $0.18 $1.1 Bn $0.9 Bn $1.8 Bn *See Significant Items Affecting Earnings in the Earnings Release Attachments. 11

12 YTD 2017 Cash Flow and Cash Balance Reconciliation ($ in Bn) $3.2 ($0.3) ($2.5) $2.2 ($1.8) $1.3 ($1.1) $0.8 $1.8 Beginning Cash Balance 1/1/17 CFFO Before Working Capital Change in Working Capital Capital Expenditures Dividends Asset Sales Acquisitions/ Other Tax Refund Ending Cash Balance 9/30/17 12

13 4Q17 and FY 2017 Guidance Summary Oil & Gas Segment FY 2017E Production > Total production of 597, ,000 boed > Permian Resources production of 141, ,000 boed 4Q17E Production > Total Production of 633, ,000 boed > Permian Resources production of 156, ,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 13

14 Occidental Petroleum Pathway to Breakeven Progress Financial Summary and Guidance Permian Resources Update Closing Remarks 14

15 3Q17 Record Well Results in Greater Sand Dunes 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 basin 2 Record well results are across multiple flow units Confident in sustainable performance with locations in excess of 2,000 in the Greater Sand Dunes Sustainable, Step Change in Well Results De-risks Breakeven Plan 3Q17 Wells Peak 30D Production Rates 1 5,000 4,000 3,000 2,000 1, ,805 CC 23 FED COM 033H 7,200 ft Oil (Bod) Wolfcamp XY 3,464 CC FED COM 034H 9,800 ft CC FED COM 033H 9,800 ft NGL (Boed) 3,672 3,563 3,824 CC FED 031H 7,200 ft 3 rd Bone Spring CC FED COM 034H 7,200 ft Gas (Boed) 4,379 4,503 CC FED 032H 7,200 ft CC 23 FED COM 006H 7,200 ft 2 nd Bone Spring nd Bone Spring Performance rd Bone Spring Performance Notes: 1 Three stream production results. 2 For top wells in basin, data is based on IHS calendar month production through August 30, 2017,and Oxy data is internal calendar month production. Cumulative Production (Mboe) 3Q17 Well 3Q17 Wells Days Online 15

16 Recent Rig Additions Begin 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 21 Subsurface characterization Customized landing and completions 16 Pad Drilling Increasing Lateral Length Increasing Record Well Results Provide Near-term Visibility to Achieving 80 Mboed Production Increase Milestone Permian Resources Horizontal Wells Online 26 New Mexico Texas Q17A 2Q17A 3Q17A 4Q17E 1Q18E 2Q18E Average Lateral 1H 2017 = ~7,000 ft 2H 2017 = ~7,800 ft 1H 2018 = ~8,500 ft

17 Occidental Petroleum Pathway to Breakeven Progress Financial Summary and Guidance Permian Resources Update Closing Remarks 17

18 Appendix

19 Appendix Contents Permian Updates Midstream and Chemicals Updates Social Responsibility, Environment, and Governance Journey to Digital Transformation Company Overview and Value Proposition 19

20 Permian Resources Wells Continue to Improve 6 Month BOE Cumulative Production 6 Month BOE Cumulative Production New Mexico Bone Spring H 16 2H Target Top Peers 2016 New Mexico Wolfcamp *Operators Include: COP, CXO, CDEV, DVN, EOG, MRO, MTDR, Mewbourne, WPX, XEC *Operators Include: APA, Broad Oak, CVX, CXO, Discovery, ECA, EGN, END, EPE, FANG, LPI, PE, PXD, SM, Surge Opg, XOM 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 Month BOE Cumulative Production 6 Month BOE Cumulative Production Texas Delaware Wolfcamp AVG Lat Length (ft) 4,169 4,937 4,871 ~6,000 5,196 AVG Lat Length (ft) 4,807 5,418 7,758 ~7,500 6,097 *Operators Include: Bopco, Bta Oil Producers, CHI, CVX, CXO, Caza, CDEV, DVN, EOG, Fasken Oil And Ranch, LGCY, *Operators Include: APA, APC, BHP, COP, CRZO, CVX, CXO, CDEV, EOG, FANG, HK, JAG, MTDR, Mewbourne, NBL, MTDR, Marshall & Winston, Mcelvain O&G, Mewbourne, Regeneration Energy, WPX, XEC, XOM PDCE, RDSA, REN, RSPP, WPX, XEC, XOM H 16 2H Target Top Peers 2016 Texas Midland Wolfcamp AVG Lat Length (ft) 4,398 ~6,700 5,092 AVG Lat Length (ft) 6,700 7,457 7,467 ~8,200 8, H 16 2H Target Top Peers H 16 2H Target Top Peers

21 Permian Resources Results and Guidance 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 > Impact of 4 rigs added mid-2017 > Shift to more New Mexico activity > Improving well results provides additional upside Q Q17 2Q17 3Q17 4Q17E 2017E *Q3 production total without impact of Hurricane Harvey and including the production divested from the Midland Basin 21

22 Achieving Plan Through Value-based Approach Current trajectory of 30% CAGR Production (Mboed) Multi-Year Permian Resources Growth 13 rigs at exit % 3-yr CAGR 8 20% 3-yr CAGR Rig Count Significant increase in 4Q17 wells online > 11 operated rigs, 6-7 in Greater Sand Dunes by 1Q18 > 2017 Capex coming in at midpoint of capital range of $ $1.8 Bn 2018 program on track for above 30% growth Low case rig count* 2017 Exit rig count* High Case rig count* *Includes estimated net non-operated rigs 22

23 Operating Capability Reduces Costs Continued Margin Improvement Through Opex Reduction Permian Resources Opex/BOE Water-handling improvement reducing surface costs $12 $12.93 $11.17 Continued lift optimization reducing downhole failure costs Operating efficiencies offsetting cost inflation $8 $8.43 $8.14 High-margin production growth $4 $ YTD Surface Downhole Supports Energy Other 23

24 Greater Sand Dunes Play-leading Well Performance Continued play-leading results from three benches >2 nd Bone Spring >3 rd Bone Spring >WolfcampX/Y Vision well design process drives improvements Improved performance in 3Q from landing and frac optimization Cumulative MBOE Value-Based Development Increases Returns Well Performance Improvements Average 2 nd Bone Spring, 3 rd Bone Spring and Wolfcamp X/Y 3Q17 7 wells 8,000 Avg. Lat. Length 1H17 11 wells 5,650 Avg. Lat. Length wells 5,350 Avg. Lat. Length Days Online 2 nd Bone Spring Landing and Frac Optimization > 45 % improvement in Q3 performance over 1H17 24

25 Greater Barilla Draw Operating Excellence & Strong Results Value-Based Development Increases Returns 2017 Barilla Draw proper Wolfcamp A Optimized Landing Point Results Oxy record wells in Texas Delaware in 2 new benches >2 nd Bone Spring >WolfcampB Barilla Draw wells continue to improve > ,000 ft wells ~70% above previous performance > ,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 Cum MBOE 2017 YTD Opex / BOE $10 $8 $6 $4 $2 $ Days Online $4.95 Average of ,000 ft wells (3) $3.43 $3.50 Lyda 16H 10,150 Average of ,000 ft wells (3) Hz Development Yields Low Operating Costs Four Greater Barilla Draw fields with all or almost all horizontal development $2.62 Red Bull South Mentone Lockridge Barilla - Birds of Prey Area Pre-2017 Wolfcamp A Wells Avg. Lateral ~4,700 Includes ~700 vertical wells $9.41 Tx Delaware - Total Operated Fields Hz well count: Avg. Hz well age: ~2 years ~ 2 years ~1.5 years ~2 years 25

26 Midland Basin - Merchant Mature Field with High Margins Value-Based Development Increases Returns Multi-bench program and operating efficiency create play-leading opex 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 Cum Oil - MBO $3 $2 $1 $- Merchant Opex / BOE $ YTD Downhole Maint Surface Other Successful Development Planning from Inception Leads to Greenfield Operating Cost First wells online in horizontals online Centralized facilities No water hauling with truck Central compression for gas lift Gas lift limits well failures and downhole cost Wolfcamp B Improvement = two high-return development benches New WC B Design All WC A Wells Old WC B Design

27 Outstanding Results in Greater Sand Dunes Area Multi Bench Development Target Formation Well Name Recent Well Results Lateral Length (ft) Peak 24 Hr (boed) Peak 30 Day (boed) Oil (%) Barilla Draw Type Log Greater Sand Dunes Brushy Canyon Federal 23 13H 4, % Avalon James 29 38H 4,730 1,132 1,115 79% 1 st BSS Cedar Canyon 23 2H 4,025 1, % New Cedar Canyon 23 Fed Com 6H 7,241 4,518 3,963 84% Cedar Canyon 22 5H 4,468 3,292 2,711 80% 2 nd BSS 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% Cedar Canyon Fed 32H 7,235 6,497 3,728 69% New Cedar Canyon Fed Com 34H 7,172 4,876 3,338 73% 3 rd BSS Cedar Canyon Fed Com 34H 9,820 3,751 3,050 71% Cedar Canyon Fed 31H 7,228 5,152 3,041 67% Cedar Canyon Fed Com 33H 9,758 3,730 3,178 75% Oxy Total 2017 Average 7,381 3,974 2,846 74% New Cedar Canyon 23 Fed Com 33H 7,228 2,898 2,460 75% Wolfcamp XY Patton 18 6H 4,401 2,774 2,150 71% Cedar Canyon 16 33H 4,418 2,397 2,049 71% Cedar Canyon 16 34H 4,235 2,287 1,967 70% Janie Conner 204H 4,500 1,980 1,221 78% Wolfcamp A B Banker 226H 4,400 1,874 1,030 76% Janie Conner 207H 4,500 1,272 1,121 72% Wolfcamp D Janie Conner 221H 4,522 2,282 1,809 39% Tiger 14 24S 28E 224H 4,376 1,719 1,417 47% Proven Economic Delineating 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 ,000 ft Brushy Canyon Avalon 1 st Bone Spring 2 nd Bone Spring 3 rd Bone Spring Wolfcamp X-Y Wolfcamp A Wolfcamp D 27

28 Improving Results in Greater Barilla Draw Area Multi Bench Development Recent Well Results Target Lateral Length Peak 24 Hr Peak 30 Day Formation Well Name Oil (%) (ft) (boed) (boed) Avalon Evaluating 1 st BS Evaluating New Collie A East N63H 9,725 1,370 1,155 84% 2 nd BS Aardvark State 6 2H 4,947 1, % Roan State 24 #51H 4, % 3 rd BS Morrison, HB 73H 4, % Big George 180 SW 3H 7, % Lyda S State 16H 10,164 3,724 3,202 84% Toyah 4-9 1N 11H 9,845 3,077 2,028 79% Wolfcamp A Buzzard State Unit #16H 7,700 2,050 1,822 74% Peck State 258 #6H 4,212 2,244 1,791 82% New Toyah 4 9 2N 12H 9,890 2,069 1,672 83% Oxy Total 2017 Average 7,394 1,888 1,517 74% Oppenheimer 188 1H 4,500 2,451 1,907 82% Wolfcamp DF 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% New Agate S 25H 7,439 2,088 1,611 70% Manhattan 183W 1H 7,092 1,954 1,584 75% Wolfcamp B Daytona Unit 1B 2H 6,947 1,897 1,544 79% New Agate S 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, % Barilla Draw Type Log Greater Barilla Draw 4,500 ft Proven Economic Delineating Avalon 1 st Bone Spring 2 nd Bone Spring 3 rd Bone Spring Wolfcamp A Wolfcamp DF Wolfcamp B Wolfcamp C 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

29 Logistic & Maintenance Hub Underway Value Chain Partnerships Lower Costs 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 OCTG Laydown Yard ~20 railcar spots Dedicated truck entry/exit Staging, returns, reclamation Strategically located in New Mexico 244 acres 3 unit train loop 30,000 tons of sand storage Supports rigs/year Operational in early 2018 Sand Transload and Storage 6 Silos 3 Unit train loops Transload capacity OxyChem Acid Facility Transload, storage, and dilution of HCI for fracs ~20 rail transload capacity Note: Slide last updated 2Q17 29

30 Added 400 Hz Locations <$50 Breakeven 16 years of inventory <$50 breakeven with 10 rigs Reached <$50 inventory additions goal since 4Q locations YTD Undeveloped Drilling Locations 3,000 2,500 2,000 1,500 1, , ,855 Midland Basin Texas Delaware Basin New Mexico Delaware Basin 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 0 4Q16 <$50 BE Drilled 1H17 Demonstrated Capex Efficiency Demonstrated Well Performance Land Improvement Evaluated New Acreage 2Q17 <$50 BE Note: Breakeven defined as positive NPV 10. Slide last updated 2Q17 30

31 Added ~20 Rig Years of Activity to <$50 Inventory Undeveloped Drilling Locations 14,000 12,000 10,000 8,000 6,000 4,000 2,855 4,250 5,725 11,963* 11,325 11,650 Midland Basin Texas Delaware Basin New Mexico Delaware Basin Permian Resources Inventory 2Q locations BE <$50 > ~300 in New Mexico > Replaced inventory from divestitures MM ft of horizontal lateral footage to inventory > Increased average length from 7,100 ft to 7,500 ft 2,000 0 Breakeven <$50 Breakeven <$60 Breakeven <$70 Additional Inventory 2Q17 Normalized to 7,100' 4Q16 *2Q 2017 increased lateral length adjustment to normalize current inventory to 7,100. **Breakeven defined as positive NPV 10. Last updated 2Q17 31

32 Permian Resources Capital Intensity Improves through 2019 $54MM 2015 & 2016 Avg 2017 Facilites Reduction All-In Capital Intensity Annual Capex $MM / Annual Wedge Mboed* $42MM 2H 2017 Rig Ramp $33MM Subsurface Characterization Engineering Longer Laterals 2018 & 2019 $27MM $23MM 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 *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. 32

33 Permian Resources Business Area Acreage Net Acres* Significant acreage & growth potential in all development areas Resources Unconventional Areas 1.4 Enhanced Oil Recovery Areas 1.1 Oxy Permian Total ~2.5MM ~637,000 net acres within the Delaware and Midland Basin boundaries ~302,000 net acres associated with 11,325 wells in unconventional development inventory New Mexico NW Shelf NM Delaware Basin TX Delaware Basin Central Basin Platform Midland Basin Resources Basin Development Areas Net Acres* NM Delaware Basin 290,000 TX Delaware Basin** 150,000 Midland Basin* * 210,000 Other Resources Unconventional Areas Total ~650,000 2Q Permian Resources Transactions** (13,000) Updated Resources Basin Acreage ~637,000 Net Acres* Divested acres offset with additional acres evaluated in 1H17 Permian Resources Acreage Permian EOR Acreage Central Basin Platform 215,000 New Mexico NW Shelf 150,000 Emerging Unconventional 50,000 Continuing Evaluation 335,000 *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. Total ~750,000 33

34 Largest Operator in the Permian PERMIAN BASIN NET MBOEPD OPERATED PRODUCTION* Liquids Advantages Through Scale 10,000 mi 2 3D seismic 130,000 mi 2 2D seismic 24,500 gross operated wells ~10,000 gross OBO wells 250 OBO wells since 2015 OXY CVX PXD APA CXO XOM XEC EOG DVN ECA EGN FANG COP PE LPI APC KMI SHERIDAN SHELL RSPP SINOCHEM BHP WPX PERM RES. ENDEAVOR QEP MTDR SM NBL LINN CPE LGCY EPE AREX SSUMY HESS CWEI REN CRZO Gas *Source: Wood Mackenzie 2016 production, 3/2/17, company NWI% production rates, operators shown represent ~85% of Permian Basin daily production Gross Oxy operated wells including producers and injectors, and idle wells 34

35 Reducing Domestic Opex Through High-Margin Growth Barrels Asset Area Opex Ranges Domestic Production Mix $2 - $4 $5 - $20 $15 - $20 Permian Resources Growth Opex / boe Permian Resources Legacy Opex / boe Permian EOR Opex / boe Growth Legacy EOR Total Domestic Opex / boe ~$14/boe Flat

36 Oxy s Competitive Advantage in Permian Unconventional Value Based Development System Subsurface Characterization Vision Well 3D Modular Development Development Scenarios Portfolio Decisions Organization Designed for Integrated Development Manufacturing Blueprint Technology + Innovation Automation and Data Capture Data Analytics Hands-Free Operations System Integration Leadership in Full Cycle Returns 36

37 Subsurface Characterization Adds Value Landing + Stimulation + Spacing Optimization 2 nd Bone Spring Net Sand Thickness and Middle Carbonate Outline Middle Carb. Outline A A 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 2 nd Bone Spring Sand Well Placement A A Seismic Interpretation of Middle Carbonate Inside 2 nd Bone Spring Sand A A 37

38 Challenging the Vision Well Adds Value Production drivers 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 Surveillance Vision Well Data analytics Implement Design the system 38

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 4 Land core-up completed Learnings from other development units applied 4 Vision wells maximizing value Infrastructure optimized

40 Permian EOR 146 Mboed net production* Differentiated Scale and Position Over 2 Bboe Net Resource Potential ~1 Bboe at <$6 F&D 1.1 MM net acres ~20k operated wells 34 CO 2 floods 70 water floods 13 gas processing plants 3 operated CO 2 source fields 2.4 Bcf injected daily * 2Q 2017 Net Production; does not include Seminole San Andres Acquisition Permian EOR Water Floods Permian EOR Plants Permian EOR CO 2 Floods 40

41 Unmatched Infrastructure Position Field ~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 CO 2 supply agreements Integrated Communications Microwave backbone across Permian Basin 41

42 Permian EOR Keys to Success: Long-term Life Cycle High-quality Reservoirs Contiguous Scale Strategic Position 1 Bboe < $6/boe F&D Technical EOR Expertise Infrastructure and CO 2 Supply Gas Processing Automation and Controls Centralized Control of Field and Plants Data Automation and Capture Data Analytics Hands-free Operations Subsurface Characterization Phased Development Cycles Surveillance and Maintenance Safety and Environmental 42

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 BOPD Primary Proven History of Maximizing Recovery Reservoir Development Stages Waterflood CO 2 Low Base Decline Generates Sustainable FCF Recovery Factor (%) 70% 60% 50% 40% 30% 20% 10% 0% Recovery of Oil in Place* CO2 ~15% Waterflood ~30% Primary ~15% Conventional Reservoirs Primary ~6-12% Unconventional Reservoirs *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. 43

44 Permian EOR Maintenance Value-based, Full Cycle Approach Annual Beam Unit Reliability 20,000 maintenance activities per month supported by: > Right-sized programs > Computerized Management System > Total cost life-cycle approach 99.6% 99.7% 99.8% 99.8% 99.9% Less than 20 of 7,000+ Beam Units Fail Each Year Drone and Infrared Camera Inspections Safer Faster Cheaper Effective Detect Hot Spots at Plants Detect Solids in Tanks 44

45 Appendix Contents Permian Updates Midstream and Chemicals Updates Social Responsibility, Environmental, and Governance Journey to Digital Transformation Company Overview and Value Proposition 45

46 Midstream and Marketing Cash Flow Improvement Drivers Annualized Midstream Cash Flow From Operations ($ MM) Actual $190 $30 $660 ($140) Forecast $50 MM of upside not currently included in breakeven plan Al Hosn plant continued optimization: 2018 Oil terminal capacity upgrade: 2H Near-term Midland to Gulf Coast spread outlook ~$ $150 1Q17 Adjustments for Downtime 1Q17 Actual $50 $290 Crude marketing spread improvement has exceeded expectations of $200 MM $510 Improvement Since 1Q17 1Q17 Domestic Other Harvey After- 3Q17 2 CFFO 1 Crude Midstream Tax Impact CFFO 1 Annualized Marketing Annualized Spread Other Midstream Seasonality ($90) Normalized to $2.10 Outlook Marketing Spread ($30) Plains Unit Distribution Reduction $100 $450 MM Breakeven Plan Target $300 MM Improvements: - $200 MM Marketing Spread - $100 MM: Al Hosn Optimization and Crude Terminal Capacity Upgrade Al Hosn 3 Optimization and Crude Oil Terminal Capacity Upgrade Notes: 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. $500 Breakeven Plan Target 46

47 Near-term Outlook for Midland to Gulf 6.00 Coast Spreads Actual Outlook Midland to Magellan East Houston Spread ($/bbl) Global refining margins expected to remain strong Global crude oil supply will be balanced assuming OPEC extension Harvey Impact on Spread New Pipeline Capacity Upper Bound Breakeven Plan Assumption: $2.10 Lower Bound Permian pipeline utilization ~85-90% Q 2Q 3Q 4Q Q 2Q 3Q 4Q Q 2Q 3Q 4Q

48 A Leader in Crude Exports from the Gulf Coast Premier 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 Mbod 1, Jan-16 Export Ban Lifted Feb-16 Mar-16 Oxy Share of US Gulf Coast Light Crude Exports Apr-16 May-16 Jun-16 OXY Light Jul-16 Aug-16 Sep-16 Oct-16 Other Exporters Light Oxy Ingleside Startup Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 48

49 Chemicals Cash Flow Improvement Drivers JV Ethylene Cracker startup complete 4CPe Plant startup: 4Q17 Capturing margin from improving pricing and operations 1,600 1,400 1,200 1, Annualized Chemicals Cash Flow From Operations ($ MM) $1,125 $150 Actual $40 $160 $1,475 ($80) $50 $30 $350 Improvement Since 1Q17 Forecast $1,475 MM Breakeven Plan Target $350 MM Improvements: - $150: Ethylene Cracker Startup - $50: 4CPe Plant Startup - $150: Market Improvement $1, Q17 CFFO Annualized Ethylene Cracker Startup Market and Operations Improvement Harvey After- Tax Impact 3Q17 CFFO Annualized Market and Operations Seasonality 4CPe Plant Market Improvement Breakeven Plan Target 49

50 Chemicals Free Cash Flow to Significantly Increase with Lower Capital Spending $mm CPe Plant during construction Construction complete and undergoing commissioning 0 Chemicals Capital Spend E Maintenance & Other Spending New Business Spending 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 climatefriendly, 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

51 Market Overview Update Major industry consolidation complete Caustic soda supplydemand balance continues to improve PVC demand improved YoY Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 $ Millions 1Q17 2Q17 3Q17 4Q17E Chemicals Pre-Tax Earnings (EBIT) Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 $/Dry Short Ton FOB US Gulf Coast 4Q16 1Q17 2Q17 3Q17 $/mcf Chemicals Profitability Drivers Caustic Soda Price Natural Gas Price Price 2 3 Notes: 1 Chemicals pre-tax earnings excluding special items. 2 IHS Domestic Average Spot Caustic Soda Price. 3 Factset natural gas prices.

52 Appendix Contents Permian Updates Midstream and Chemicals Social Responsibility, Environmental, and Governance Journey to Digital Transformation Company Overview and Value Proposition 52

53 Reporting on Social Responsibility Since 1995 Environment, Social Responsibility and Governance are fundamental to our success and reputation as a Partner of Choice. 53

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 54

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 CO 2 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 CO 2 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 55

56 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 Cost / bbl of water 2017 Delaware Basin YTD Completion Water Usage Fresh Water Brackish Water Recycled Water $4 $3 $2 $1 $ % 5% $ % Sand Dunes Cost Savings Per Barrel* $1.50 $2.00 $1.50 $3.6MM savings from recycling program** $0.75 $- Truck Produced Original Water Pipe Improved Produced Water Recycle Current Produced Water + Truck Completion + Truck Completion for Completion Water Water Water Produced Water Costs Completion Water Costs Water Recycling *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/bbl to $0.75/bbl) $

57 C0 2 EOR Process Makeup CO 2 Supplied from Anthropogenic Sources Makeup CO 2 Supplied from Pipeline Gas Plant Gas & NGL Sales CO 2 Recycled from Gas Plant CO 2 Producer wellbore Production Produced Gas Emissions Reducing Opportunity Injection well Oil / Water / Gas Separator Oil Sales Drive water CO 2 Water Miscible Zone Oil Bank Producing Reservoir 57

58 How does CO 2 EOR Work Physics of Miscible CO 2 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 CO 2 Injection Water Injection Oil (Red) Sequestered CO 2 (Yellow) 58

59 Appendix Contents Permian Updates Midstream and Chemicals Updates Social Responsibility, Environment, and Governance Journey to Digital Transformation Company Overview and Value Proposition 59

60 Our Journey to Digital Transformation Production Optimization Institutionalized Processes and Tools Single reporting repository Focus on analysis and decision making Consolidated ERP Systems Integration of operational, technical and financial data Global Supply Chain Single Chart of Accounts Technical Data Management Technical Data Consolidation Global Well Naming Convention Field Automation Standardized End Devices Segregation of Automation Network Secured Remote Access to Real time Data Process Historian Next Generation Production Optimization Real time Data Historian Predictive Analytics Advanced Surveillance Smart Oilfield Edge Computing Internet of Things Cloud and Mobility Big Data and Analytics Cognitive Service and Machine Learning UAV Virtual Reality 60

61 Data Science Going Beyond Interesting Data Collection & Profiling Insight & Recommendations Computational Methods Key Levers Oxy & Industry Expertise Data & Analytics Domain Expertise Data Preparation & Tagging Data Quality & Cleaning Data Forensics & Profiling Bayesian Analysis Survival Analysis Uncertainty Analysis Statistical Methods Visualization Benchmarking Exploitation & Exploration Design of Experiment Statistical Learning (Machine Learning) Spatial/Temporal Analysis Optimization Artificial Intelligence Numerical and stochastic Simulation Signal Processing Network Analysis Computational Intelligence Natural Language Processing Image/Voice Processing Data Structure & Classical Algorithms University Partnerships O&G Industry Research Outside Industry Research Commercially Viable Algorithms Vendors IT Data Management 61

62 Driving the Bit Step Changing Performance Identify Understand Engineer Implement Problem: Inefficient use of rig energy resulting in slow and higher cost drilling > Downhole tool failures Re-Engineer BHA* Real Time Monitoring from Anywhere > 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 Rate of Penetration (ft/hr) Alternative Drill Pipe Increase BHA* Stiffness Redesign Bit Bit Vibration Pump Pressure Directional Control Weight Transfer 31 30% Drilling Days 7,500 Lateral (Rig Release to Rig Release) 22 28% 16 25% 12 Weight on Bit *BHA = bottom hole assembly 62

63 Driving the Bit the Target $325K avg. per rig savings Vendor performance metrics Increase in rate of penetration Problem Well avoidance Optimal path determination (staying in producing Bit Algorithm Predicts bit location using physics +machine learning Calculates dogleg severity, build/turn rate, motor 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 Planned Trajectory Max DLS limit = 11 degrees Max DLS limit = 14 degrees Max DLS limit = 24 degrees Actual Trajectory 63

64 Driving the Reservoir Target=$100MM Observation Well Injection Well Vent Well Steam/Water/CO2 Leverage field data and new data sources Optimize over larger areas Integrates w/existing workflow Significantly lower computational costs Field decisions that optimize daily total field production Optimizer Producing Well Reservoir & Operational Facilities Temp, Press Injection Production Injection Well Data Production Well Data Maximize NPV honoring economic, operating, and well constraints by generating thousands of what if scenarios High Speed, Low Fidelity Reservoir Models Historical/field data to calibrate and quantify uncertainty 64

65 Driving the Well Increase run life Earlier detection of failures Lift System Diagnostic/Optimization Leverages artificial intelligence and pattern recognition Proprietary deviated well algorithms based on mechanical engineering+applied mathematics Improve staff efficiency, quality Industry leading capabilities into Oxy s proprietary lift platform (OxyLift) 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. Risk vs Cost/Complexity Combine maintenance cost factors and risk of failures to optimize preventative maintenance. Time Risk of Failure Risk of Total Losses Risk of Additional Cost 65

66 Appendix Contents Permian Updates Midstream and Chemicals Updates Social Responsibility, Environment, and Governance Journey to Digital Transformation Company Overview and Value Proposition 66

67 Delivering Consistent Annual Dividend Growth ($/share) $28.00 $ : Oxy dividend CAGR 13.7% vs S&P CAGR 7% Annual Dividends Paid Cumulative Dividends Paid $23.38 $26.46 $20.00 $17.39 $20.36 $16.00 $14.51 $12.00 $8.00 $4.00 $0.00 $0.50 $0.50 $1.02 $1.57 $2.22 $3.02 $0.52 $0.55 $0.65 $0.80 $0.94 $3.96 $5.17 $6.48 $7.95 $9.79 $1.21 $1.31 $1.47 $1.84 $2.16 $11.95 $2.56 $2.88 $2.97 $3.02 $ Q17 Ann. Note: Dividends paid as per the Record Date 67 67

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 Value Growth - Annual ROCE for Oxy vs. Average of Competitors 30% 20% 10% 00% (10%) (20%) (30%) OXY ROCE Competitors ROCE* *Competitors ROCE represents a simple average of APA, APC, COP, CVX, DVN, EOG, HES, MRO and XOM 68

69 Value Growth Focus on valuedriven growth - Top quartile returns Positioned to return to double-digit returns 10% 0% (10%) 2016 ROCE* (20%) (30%) HES DVN CXO APC MRO APA EOG COP PXD OXY CVX XOM *Calculated based on public information and on a consistent basis Companies listed alphabetically : APA, APC, COP, CVX, CXO, DVN, EOG, HES, MRO, PXD, XOM 69

70 Value Growth Significantly Reduced Development Cost F&D (Organic) $/Boe $/Boe OXY Competitor Peers* *Competitor Peers include APC, CVX, CXO, DVN, EOG, HES, MRO, PXD. Excludes APA, COP, XOM due to negative F&D. 70

71 Longest Legacy International Operations: Colombia and Oman 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 Oman: Assisted with the discovery and started development of Safah Field in A 15 year contract extension was signed for Block 9 this year. Blocks 6227 expires and in expire in Block 62 expires in Oman: Assisted with the discovery and started development of Safah Field in A 15-year contract extension was signed for Block 9 this year. Blocks 27 and 53 expire in

72 Additional Core Middle East Assets ISND and ISSD: Offshore development in Qatar. ISND contract for 25 years initiated in ISSD contract expires in 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 worldclass mega-project. 72