Chevron 2016 Investor presentation

Transcription

1 Chevron 2016 Investor presentation August 2016 Corporation

2 Cautionary statement CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 This presentation of Chevron Corporation contains forward-looking statements relating to Chevron s operations that are based on management s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words or phrases such as anticipates, expects, intends, plans, targets, forecasts, projects, believes, seeks, schedules, estimates, positions, may, could, should, budgets, outlook, on schedule, on track, goals, objectives and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, many of which are beyond the company s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining, marketing and chemicals margins; the company s ability to realize anticipated cost savings and expenditure reductions; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of the company s suppliers, vendors, partners and equity affiliates, particularly during extended periods of low prices for crude oil and natural gas; the inability or failure of the company s jointventure partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company s operations due to war, accidents, political events, civil unrest, severe weather, cyber threats and terrorist acts, crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries or other natural or human causes beyond its control; changing economic, regulatory and political environments in the various countries in which the company operates; general domestic and international economic and political conditions; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant operational, investment or product changes required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce greenhouse gas emissions; the potential liability resulting from other pending or future litigation; the company s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; material reductions in corporate liquidity and access to debt markets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; the company s ability to identify and mitigate the risks and hazards inherent in operating in the global energy industry; and the factors set forth under the heading Risk Factors on pages 21 through 23 of the company s 2015 Annual Report on Form 10-K. Other unpredictable or unknown factors not discussed in this presentation could also have material adverse effects on forward-looking statements. Certain terms, such as unrisked resources, unrisked resource base, recoverable resources, and oil in place, among others, may be used in this presentation to describe certain aspects of the company s portfolio and oil and gas properties beyond the proved reserves. For definitions of, and further information regarding, these and other terms, see the Glossary of Energy and Financial Terms on pages 50 and 51 of the company s 2015 Supplement to the Annual Report and available at Chevron.com. As used in this presentation, the term project may describe new upstream development activity, including phases in a multiphase development, maintenance activities, certain existing assets, new investments in downstream and chemicals capacity, investment in emerging and sustainable energy activities, and certain other activities. All of these terms are used for convenience only and are not intended as a precise description of the term project as it relates to any specific government law or regulation. Corporation 2

3 Key messages Maintain and grow dividend is the priority Improve free cash flow by: Reducing capital and operating spend Growing volume and margin Use strong balance sheet to complete projects under construction Positioned to improve returns and selectively grow in lower price environment 3

4 Leading operational excellence performance Days away from work rate 0.10 Oil spills to land or water Thousands of barrels CVX ranking relative to competitors, 1 being the lowest rate Competitor range: BP, RDS, XOM CVX ranking relative to competitors, 1 being the lowest rate Competitor range: BP, RDS, XOM Source: Annual company sustainability reports. DAFWR XOM is lost time incident rates; RDS is lost time incident rates for injuries only. Oil spills to land or water when needed, units converted to thousand bbl based on the following assumptions 1 ton = 7.3 bbl 1 bbl = 0.16 cubic meters 1 bbl = 159 liters 4

5 Financial priorities Maintain and grow dividend Fund capital program for future earnings Maintain strong balance sheet Indexed dividend growth Basis: 2005 = ~9 % compound annual growth rate Return surplus cash to stockholders Chevron S&P 500 Competitor average: BP, RDS, TOT, XOM Competitor range: BP, RDS, TOT, XOM Source: Public information 5

6 Financial performance Earnings Cash flow from operations C&E spending 2Q16 YTD $ (2.2) billion $ 3.7 billion $ 12.0 billion Low price environment Responding to market Completing projects underway Capital and operating spend reduction Asset sales for value Prudently using balance sheet Debt ratio ~23 % Dividends paid $ 4.0 billion 6

7 Improving free cash flow Cash flow after dividends* (including asset sales) $ billions 10 5 Cash flow from operations DS&C/ Upstream Other TCO financing/ asset sales Reduced spend 0 (5) (10) (15) 2015 Actual* $52/bbl Reduced cash C&E spend 2017* $52/bbl Price recovery Further flexibility depending on market Volume and margin growth *Cash flow after dividends = estimated cash flow from operations plus asset sales, less cash C&E, less dividends includes asset sales proceeds of $5.7B at $52/bbl Brent is for illustration purposes only and not indicative of Chevron s forecast Corporation 7

8 Cost and procurement activities Sustainable actions Organizational activities ~4,000 through 1Q 2016 On target to reach ~8,000 Efficiency gains Logistics Drilling 2,622 Examples of efficiency gains Thailand drilling efficiency Average days per 10,000 feet drilled Rushmore benchmarking Chevron Southeast Asia competitor average - - ~45% Strategic supplier engagement Africa logistics efficiency ~40% Estimate Number of vessels 8

9 Spend momentum Total capital & exploratory Quarterly $ billions C&E is trending to lower end of guidance range YTD 2016 vs. YTD 2015: -31% OPEX and SG&A Quarterly $ billions OPEX reductions continue to be realized avg 2015 avg 1Q 2Q 3Q 4Q YTD 2016 vs. YTD 2015: -8% avg 2015 avg 1Q 2Q 3Q 4Q Quarterly average Total C&E includes affiliate spend 2016 Quarterly average 2016 OPEX and SG&A = operating, selling, general and administrative expenses as reported on income statement (excludes affiliate spend) 9

10 Reducing spend Total capital & exploratory $ billions 40 $25-28 guidance OPEX / SG&A $ billions 30 $17-22 guidance Projects under construction in 2015 TCO FGP / WPMP Base & other Total C&E includes affiliate spend. TCO FGP / WPMP = Tengiz Future Growth Project and Wellhead Pressure Management Project OPEX / SG&A = operating, selling, general and administrative expenses as reported on income statement (excludes affiliate spend) 10

11 Shorter-cycle, higher return investments Total capital & exploratory Percentage of capital program Spend profile Increase in shale and tight More brownfield opportunities Fewer major capital projects Reduced execution risk 40 % 45 % 60 % 65 % Base and short-cycle TCO FGP / WPMP Growth MCPs and exploration Total C&E includes affiliate spend. TCO FGP / WPMP = Tengiz Future Growth Project and Wellhead Pressure Management Project 11

12 Growing upstream volume Projected net production MMBOED Growth Major capital projects online Shale and tight % growth* Uncertainties / timing Divestments Price effects Spend levels *Includes estimated impact of divestments 12

13 Growing upstream margin Projected cash margin* $ per BOE 30 New barrels accretive 20 $ 70/bbl $ 60/bbl Divestment of lower margin barrels 10 $ 52/bbl $ 52/bbl Expansion strongly linked to oil prices *Estimated after-tax cash margin based on Chevron s internal analysis 13

14 Axis Title 10 5 Asset sales program Proceeds $ billions (before tax) Target ~ $ 5 10 Successful program Well-timed transactions Captured good value $ 5.7 Public domain Hawaii downstream South Africa downstream Divestment criteria Non-strategic fit Unable to compete for capital $ 2.9 Caltex Australia Nigeria Canada downstream Myanmar Receive fair value Geothermal $ YTD annual average

15 Strong balance sheet Reported annual debt ratio and debt capacity Debt ratio 70% 50% 30% TOT BP 10% RDS (Post-BG) Debt capacity: incremental debt capacity to 30% debt ratio ($ billions) XOM Others: APC, COP, DVN, ENI, EOG, HES, MRO, OXY, STO Source: Public information as of 4Q ENI based on 3Q 2015 data; RDS/BG post-deal based on average of analyst estimates 15

16 Pathway to improve returns Adjusted ROCE Percent Lower pre-productive capital from longcycle projects More high return, short-cycle and brownfield spend Project execution improvements Lower unit operating expense Oil-price exposure 5-year 1-year Competitors: BP, RDS, TOT, XOM S&P 500 Source: Adjusted ROCE analysis as of 4Q15 based on Chevron estimates and public information treated on a consistent basis. Excludes special items. S&P on non-adjusted reported basis. 16

17 Upstream Corporation 17

18 Upstream portfolio Strategically positioned geography Percent of total commercial reserve portfolio 7% Canada 39% 12% 23% 2% 8% Europe 12% 0% Russia 8% 5% Caspian Strong, flexible portfolio World class legacy assets Premier shale positions Outstanding mature assets Strong deepwater holdings US 2% 13% Middle East 27% 12% 15% 15% Asia / Oceania Africa / Latin America CVX Competitors: BP, RDS, TOT, XOM Source: Wood Mackenzie. Estimate of remaining reserves (on a reported basis) as of 1/1/2016; does not include sub-commercial resources defined as an estimate of discovered resources not expected to be developed in the near-term 18

19 Strong reserves performance Reserve replacement ratio 5 year reserve replacement BBOE 10.5 Production Additions % 1 year 113 % 5 year Asset sales (4.8) (0.2) Numbers do not add due to rounding 19

20 Leading exploration performance 1.8 BBOE Resource* adds in % Success rate in 2015 $ 1.22 Unit finding cost in 2015 Discovery costs $/BOE Resource additions BBOE Resource* adds 10 year total % Success rate 10 year average $ 1.73 Unit finding cost 10 year average Competitor range: BP, RDS, TOT, XOM * Recoverable resources as defined in the Supplement to the Annual Report Source: Wood Mackenzie Company Exploration Benchmarking October

21 Improving efficiency Deepwater Gulf of Mexico Intelligent well completions enhance economic recovery Basin experience and standardization improving performance Tengiz New well stimulation method reduced costs ~70% Debottlenecking increased production capacity ~16 MBOPD Technology 30% production increase from artificial intelligence techniques in California 2,000+ critical rotating machines centrally monitored Average days per 10,000 feet drilled Transportation cost reduction 2014 competitor average 2015 competitor average ~25%

22 Gorgon / Wheatstone Gorgon Train 1 Current rate ~90 MBOED Producing at 70% capacity Full capacity expected by 4Q16 Train 2 first LNG early 4Q16 Train 3 first LNG 2Q17 Wheatstone All 9 wells flow tested and ready for production Plant structural, piping and cabling work currently ahead of plan Train 1 first LNG expected mid-2017 Train 2 first LNG expected 6-8 months after Train 1 22

23 Other 2016 start-ups Alder First production expected 2H 2016 Chuandongbei All three trains online Mafumeira Sul All four platforms installed Hook-up & commissioning ongoing First production expected 2H 2016 Angola LNG Achieved 75% capacity Four LNG cargoes shipped post restart Planned shut-down for strainer maintenance is underway Sustained production expected 3Q16 Bangka First production expected 2H

24 Leveraging Permian performance to other shale & tight assets Duvernay Appraisal program advancing Best-in-class drilling; days per well reduced ~35% Unit development cost decreased ~35% Vaca Muerta Initiated horizontal factory mode Horizontal well costs reduced ~20% Improved well designs have achieved IP rates ~800 BOED Unit development cost decreased ~30% Appalachia Pacing investment Well costs reduced ~35% Cycle time shortened ~45% EUR increased ~30% Unit development cost decreased ~40% Duvernay baseline 2H 2014 Vaca Muerta baseline 4Q 2014 Appalachia baseline 1Q

25 Competitive Permian growth Advantaged acreage ~2 MM acres 1 MM acres in Delaware Basin 0.5 MM acres in Midland Basin ~85% no or low royalty ~9 BBOE resource 1 Midland & Delaware net acres 3 (1000 acres) Chevron Breakevens 2 $ WTI 1,300 4,000 5,500 Net production 4 Midland & Delaware MBOED Potentially recoverable resources as defined in the Supplement to the Annual Report 2 Figures reflect cumulative well counts for ~30% of operated acreage Breakevens per Wood Mackenzie definition: 10% rate of return at flat real oil price 3 Per Wood Mackenzie, top eight acreage holders in the Delaware and Midland Basins 4 Reflects CVX shale and tight production only <$40 <$50 <$ Base decline Growth Growth range Actual production 25

26 Competitive Permian growth Competitive development costs Paced, efficient development of prioritized queue JV and industry best practices have allowed accelerated learning EUR performance on target Improvements continue Cost reductions in both drilling and completions Characterization of our acreage Future developments will benefit from infrastructure investments made today Average development cost 1 $/BOE $20 $15 $10 $5 $0 2Q15 3Q15 4Q15 1Q16 2Q16 Chevron operated Well information Non-operated JV Recent CVX cost performance 2 (YTD 2016) Total D&C ($MM) Pad Lateral (ft.) Best Avg Salado Draw 5, Bradford Ranch 7, Greater Bryant G 7, Greater Bryant G 10, Includes drilling, completion, facilities, and G&A costs 2 Includes drilling and completion costs only 26

27 Base projects Well factories Gulf of Thailand San Joaquin Valley Indonesia Base deepwater Focused on development of existing assets Agbami, Tahiti, Jack / St. Malo, Caesar Tonga, Mad Dog Asset enhancements Infill drilling Debottlenecking and reliability upgrades Platong II Tahiti Tengizchevroil Second Generation Project 27

28 FGP / WPMP Final investment decision (FID) in July Wellhead Pressure Management Project (WPMP) Lower back-pressure on wells to maintain the existing plants at full capacity Future Growth Project (FGP) Increasing capacity ~260 MBOED utilizing proven technology Improves reservoir recovery Extends the production plateau by increasing TCO gas handling capability Expected incremental recovery ~2 BBOE Production profile Start-up in 2022 Second Generation Plant Original Plant FGP WPMP All figures shown are TCO 100% 28

29 FGP / WPMP financials Project cost Total: $36.8 B Facilities: $27.1 B Wells: $3.5 B Contingency / Escalation: $6.2 B ~$18/BOE project development cost Financing in place All figures shown are TCO 100% Accommodation building construction 29

30 FGP / WPMP execution readiness Critical lessons learned incorporated into FGP / WPMP design and planning Increasing engineering maturity at FID Strengthening design assurance Optimizing contracting strategy Verifying execution readiness Improving quality management Engineering > 50% at FID; underground piping, electrical and foundations in 3D model; 85% of equipment on order at FID Process design and specifications of major equipment verified; facilities hazard & operability studies complete at FID Module fabricator involved in early design; integration of owner and EPC teams; matching scope of work to contractor capabilities 5,300 camp beds available now; dredging ~50% complete; fabrication starts after 90% model review Project engineers assigned to equipment packages from design through start-up; Quality Control personnel co-located at main factories 30

31 FGP / WPMP Builds on previous successes Great partnership World class reservoir Proven technology Now is the time Reservoir pressure decline Capture market opportunities Project synergies Upside potential Future infill wells Debottlenecking opportunities 31

32 Future opportunity queue Kitimat LNG Midland & Delaware Basins Liard Basin Horn River Basin Deepwater Gulf of Mexico Future major capital project Shale & tight Conventional exploration & appraisal wells Duvernay Marcellus Utica Tahiti Vertical Expansion Tahiti Upper Sands Development Mad Dog 2 Suriname Vaca Muerta Nigeria Rosebank Captain EOR Kurdistan Region of Iraq Bonga SW / Aparo Agbami Infill Republic of Congo TCO FGP / WPMP Wafra Steamflood Western Australia Ubon Gendalo-Gehem Bight Basin 32

33 Downstream & Chemicals Corporation 33

34 Downstream portfolio Fuels refining & marketing Integrated value chains Portfolio 2015 capital employed Chemicals Cost advantaged, globally positioned 35 % 65 % 2018 capital employed 42 % 58 % Value chains Refinery Chemicals & lubricants Refining & marketing Chemical plant Chemical sales office Additives manufacturing & supply 34

35 Strategy focused on competitive returns Deliver competitive returns and grow earnings across the value chain Improve operational excellence Grow higher return segments Petrochemicals Lubricants and additives Focused refining and marketing Integration with upstream Increase near-term cash 35

36 Demand growth points to attractive segments global product demand growth Compound annual growth rate Premium Base Oil Petrochemicals* Additives Finished Lubricants Distillate global fuels demand growth MMBD Gasoline 0% 5% -2 North America Europe / Middle East Latin America Asia Pacific Gasoline Distillate *Ethylene, propylene, butadiene, benzene, and paraxylene Source: NexantThinking, Kline & Company, Wood Mackenzie and Chevron estimates 36

37 Impact of lifting the U.S. crude export ban Levels the playing field U.S. light-sweet crude gets global parity pricing U.S. heavy coking margins improve relative to U.S. light cracking margins Minimal impact to California refiners 2015 U.S. crude capacity by region 100% 50% Chevron Industry West coast Gulf coast Mid-continent East coast Source: EIA as of November

38 Chevron Phillips Chemical USGC petrochemicals project Overview 1,500 kmta ethylene, Baytown, Texas 1,000 kmta polyethylene, Old Ocean, Texas 500 kmta HDPE 500 kmta LDPE Advanced proprietary technology Progress ~80 % complete (>6,000 people onsite) Polyethylene reactors in-place Ethylene major compressors in place; furnace erection in progress Projected start-up