Chevron 2017 Investor presentation

Transcription

1 Chevron 207 Investor presentation September 207

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 995 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 energyrelated industries. Words or phrases such as anticipates, expects, intends, plans, targets, forecasts, projects, believes, seeks, schedules, estimates, positions, pursues, may, could, should, budgets, outlook, trends, guidance, focus, on schedule, on track, goals, objectives, strategies, opportunities 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 forwardlooking 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 forwardlooking 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 joint-venture 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 or shares or the delay or failure of such transactions to close based on required closing conditions; the potential for 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 20 through 22 of the company s 206 Annual Report on Form 0-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 5 of the company s 206 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. As used in this presentation, the terms Chevron, CVX and the company may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or to all of them taken as a whole. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs. 2

3 Key messages Cash flow after dividends (including asset sales) $ billions.0 Growing free cash flow (4.8) (3.) Focused on improving returns (7.8) (8.8) Realizing value from advantaged portfolio H5 2H5 H6 2H6 H7 Cash flow after dividends = change in cash and marketable securities and change in debt. Reconciliation of cash flow after dividends including asset sales can be found in the appendix. 3

4 Operational excellence Days away from work rate Indexed Tier and Tier 2 Loss of Containment 0.0 Basis: 202 = Industry leading performance CVX ranking relative to competitors, being the lowest rate Competitor range: BP, RDS, XOM Source: Annual company sustainability reports. XOM is lost time incident rates; RDS is lost time incident rates for injuries only; TOT is not included in competitor range due to reporting differences. Loss of Containment - Company data. American Petroleum Institute Recommended Practice (RP) 754 defines Tier loss-of-primary-containment (LOPC) incident as an unplanned or uncontrolled release of any material, including non-toxic and nonflammable materials from a process that results in an injury, shelter in place or evacuation, fire, or material release that meets the thresholds as defined in the RP 754. A Tier 2 process safety event is an LOPC with lesser consequence. 4

5 2Q7 YTD financial highlights Earnings $4. billion Earnings excluding special items and FX * $4.0 billion Cash flow from operations / excluding working capital $8.9 billion / $0. billion Debt ratio (as of 6/30/207) 22.7% Dividends paid $4. billion * Reconciliation of special items and FX can be found in the appendix. 5

6 Cash margin per barrel Upstream cash margin per barrel $ per BOE Downstream cash margin per barrel 2 $ per BBL CVX ranking relative to competitors, being the best Competitor range: BP, RDS, TOT, XOM Upstream after-tax cash margin sourced from supplemental information on oil & gas producing activities (in 0-K, 20-F) and other public information placed on a consistent basis along with Chevron estimates. Includes affiliates. Adds back depreciation and depletion, unproved properties valuation, accretion and exploration expense to results of producing operations, excluding asset sales gains and losses. CVX ranking relative to competitors, being the best Competitor range: BP, RDS, TOT, XOM 2 Downstream after-tax cash margin sourced from public information (in 0-K, 20-F and other disclosures) placed on a consistent basis along with Chevron estimates. Excludes chemicals; TOT data includes base chemicals. Adds DD&A to reported earnings, excluding asset sales gains or losses. 6

7 Financial priorities remain unchanged Maintain and grow dividend Fund capital program for future earnings Maintain strong balance sheet Return surplus cash to stockholders * range at $50/bbl Brent. Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. 29 consecutive years of annual dividend payout growth 0-year compound annual growth rate at ~8% Expected C&E range of $7-22 billion Expected debt ratio range of 20-25% * $45 billion in share repurchases from

8 207 cash flow balancing Cash flow after dividends (including asset sales) $ billions 5 0 Asset sales / other 207 $50/bbl Price upside Higher upstream margins and volumes (5) (0) Actual Actual $44/bbl $44/bbl 206 Normalized Adjusted $50/bbl $50/bbl 2 Upstream growth 3 Absence of Absence TCO loan of TCO Loan Reduced cash Reduced C&E spend Cash C&E Spend Lower and flexible spend Value accretive asset sale proceeds (5) Cash flow after dividends = estimated change in cash and marketable securities and change in debt. 2 Normalization assumes $350MM cash flow impact per $/bbl change in Brent price. Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. 3 Includes volume growth and increase in cash margins/bbl (margins include impact of working capital, deferred taxes, affiliate distributions, other). 8

9 Free cash flow going forward Cash flow after dividends (including asset sales) $ billions $70/bbl range Free cash flow increase at $50/bbl 6 4 FCF growth Asset sales $60/bbl range Peer leading oil price leverage 2 $50/bbl $50/bbl Estimated cash flow after dividends = estimated change in cash and marketable securities and change in debt. Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. 9

10 Production outlook Projected net production MMBOED % production growth in 207 without asset sales 2 Growth Major capital projects Shale and tight Uncertainties / timing Divestments Price effects Status of PZ Ramp-pace of MCPs Excluding impact of divestments Including impact of divestments As of March 7, Estimated growth range reported on 4Q6 earnings call, based on estimated impacts of uncertainties at $50/bbl Brent. Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. 0

11 Worldwide net oil & gas production MBOED 2, % Y-O-Y growth without 207 asset sales guidance range* Current estimated impact of 207 asset sales in MBOED No impact on 2Q YTD production due to 207 asset sales 2,600 2Q YTD 207 guidance range uncertainties 2,728 Wheatstone start-up & ramp-up 2,400 2,594 Base decline and PSC effects Turnaround durations 2, Actuals 207 Expected impact of 2H 207 production Unexpected operational issues Other external events (e.g. Partitioned Zone restart) * Production outlook excludes estimated impact of 207 divestments

12 Growing upstream operating cash margin Projected operating cash margin* $ per BOE $70/bbl $60/bbl New barrels accretive Divestment of lower margin barrels 0 $50/bbl $50/bbl $50/bbl Continuous improvement in cost structure *Estimated after-tax upstream cash flow from operations margin based on Chevron s internal analysis. Adds back impact from non-cash items. Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. 2

13 C&E program Total capital & exploratory $ billions $9.8 $7-22 Sustained low spend through 2020 At flat $50/bbl, spend near bottom of range budget guidance Downstream & other Base producing assets Gorgon / Wheatstone FGP / WPMP Exploration / growth MCPs Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. 3

14 C&E reprioritization & optimization Percentage of total capital & exploratory Exploration / other TCO FGP / WPMP Gorgon / Wheatstone CPChem cracker Other 207 / 208 MCP start-ups Permian basin Other short-cycle & brownfield spend budget ~75% of 207 spend generates cash within two years MCPs being completed High return base and shale & tight Expected to generate cash within two years FGP / WPMP Exploration / other projects 4

15 Spend reductions Total capital & exploratory Quarterly 2Q 207 YTD C&E OPEX and SG&A Quarterly $ billions 2 56% below 204 average Total C&E $8.9B Cash C&E $6.8B $ billions full year forecast C&E $9B Q 207 YTD OPEX 25% below 204 average OPEX & SG&A $.2B avg 205 avg Quarterly average 206 avg 207 avg 207 full year forecast OPEX and SG&A $.5-$2B below 206 actual avg 205 avg Quarterly average 206 avg 207 avg 2Q 207 YTD quarterly average 2Q 207 YTD quarterly average Total C&E includes affiliate spend. OPEX and SG&A = operating, selling, general and administrative expenses as reported on income statement (excludes affiliate spend). 5

16 Asset sales program Proceeds $ billions (before-tax) 0 In public domain Bangladesh* Canada downstream* South Africa* Target ~$5-0 2Q 207: $0.4 billion Within target range South Natuna* 5 Trinidad and Tobago* $2.5 H7 Divestment criteria remains unchanged: Strategic fit Unable to compete for capital $2.8 in 206 Receive fair value * Signed sales and purchase agreement 6

17 Balance sheet strength Debt ratio Percent competitor average 32.0% 24.% Differentiated strong balance sheet Expected 20%-25% range through CVX actual CVX average CVX expected range Competitor group (BP, RDS, TOT, XOM). *Source: Public information range at $50/bbl Brent. Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. 7

18 Appendix 8

19 Reported earnings ($MM) 2Q6 3Q6 4Q6 Q7 2Q7 Upstream (2,462) , Downstream,278, ,95 All Other (286) (236) (872) 239 (598) Total reported earnings (,470), ,682,450 Diluted weighted avg. shares outstanding ( 000),87,995,883,342,890,044,895,393,893,04 Reported earnings per share $(0.78) $0.68 $0.22 $.4 $0.77 Special items ($MM) UPSTREAM Asset dispositions (70) Impairments and other* (2,830) (360) Subtotal (2,900) (200) DOWNSTREAM Asset dispositions Impairments and other* ALL OTHER Subtotal Impairment and other* (70) Subtotal (70) Total special items (2,40) (270) Foreign exchange ($MM) Appendix: reconciliation of non-gaap measures Reported earnings to earnings excluding special items and FX Upstream (274) (4) Downstream (26) (4) 53 (46) 3 All other (24) (9) (33) 79 4 Total FX (24) 3 Earnings excluding special items and FX ($MM) Upstream ,9,057 Downstream 84, ,92 All Other (262) (227) (839) 60 (532) Total earnings excluding special items and FX ($MM) ,323,77 Earnings per share excluding special items and FX $0.35 $0.49 $0.2 $.23 $0.9 *Includes asset impairments & revaluations, certain non-recurring tax adjustments & environmental remediation provisions, severance accruals and any other special items. 9

20 Appendix: reconciliation of non-gaap measures Cash flow after dividends including asset sales $MM 4Q4 Q5 2Q5 3Q5 4Q5 Full Year 205 Q6 2Q6 3Q6 4Q6 Full Year 206 Q7 2Q7 Cash and cash equivalents 2,785 2,675 2,56 2,933,022 8,562 8,764 7,35 6,988 6,983 4,762 Time deposits 8 Marketable securities Total cash 3,25 3,07 2,52 3,239,332 8,879 9,084 7,672 7,00 6,994 4,775 Total debt 2,3 27,784 33,892 3,869 35,838 38,549 42,339 45,085 45,585 46,26 45,256 42,864 Change in total cash (08) (586) 78 (,907) (,883) (2,453) 205 (,42) (67) (4,33) (7) (2,29) Change in total debt 6,08 (2,023) 3,969 2,7 0,765 3,790 2, ,577 (870) (2,392) Cash flow after dividends including asset sales (change in total cash less change in total debt) (6,26),437 (3,25) (4,68) (2,648) (6,243) (2,54) (,92) (,22) (,908) H5 2H5 4 H6 2H6 H7 (4,779) (7,869) (8,784) (3,24),036 Cash flow after dividends including asset sales = change in cash and marketable securities and change in debt. 2 Total debt = the sum of short-term debt, long-term debt, and capital lease obligations and 205 quarterly debt figures conformed to ASU (adopted January 206) 4 2H5 Rounded to $(7.8) billion on slide 3 20

21 Supply and demand Changes to liquids supply & demand Million barrels per day New OPEC or non-opec supply sources required to offset decline and meet demand growth Short-term oil markets on path to rebalancing with new sources of supply needed long-term Source: IEA World Energy Outlook 206, New Policies Scenario 2

22 Oil & gas remain key energy sources Global energy demand Million barrels of oil equivalent per day >50% of global energy Oil & gas consumption to 2035 Growth rate of ~2.0% Natural gas demand % growth rate Oil demand Asia-Pacific drives 60% of the growth in oil demand and 45% of the growth in gas demand Current 2025 Oil Natural gas Coal Other: Nuclear, Hydro, Biomass, and Renewables Source: IEA World Energy Outlook 206, New Policies Scenario 22

23 Pre-FID and US L48 future drilling production by breakeven in 2025 Source: Wood Mackenzie Oil Supply Tool, point forward breakevens weighted by 2025 liquids production, 5% discount rate. H 207 dataset 23

24 Lower 48 onshore oil outlook Source: Wood Mackenzie 24

25 Upstream

26 Focusing on returns Expanding cash and earnings margins Effectively allocating capital High-grading the portfolio Image: Sonam platforms 26

27 Improving upstream performance Increasing cash inflows Net production MMBOED % growth Increasing production with higher cash margins Decreasing cash outflows Upstream capital & exploratory $ billions Actual Estimate excluding impact of divestments Actual Budget Cash margin Percentage of total net production <$5 per BOE $5 $25 per BOE >$25 per BOE Estimated after-tax cash margin at $50/bbl in 206 & 207. Adds back impact of non-cash items. Note: $50/bbl Brent is for illustrative purposes only and not necessarily indicative of Chevron s price forecast. Decreasing capital and production costs Production cost 2 $ per BOE CVX ranking relative to competitors, being the best Competitor range: BP, RDS, TOT, XOM 2 Sourced from supplemental information on oil and gas producing activities (in 0-K, 20-F). Production expenses (excluding taxes) + taxes other than income + other expense/income (excluding asset sale gains/losses). 27 3

28 Resources to production Resources 0-year resource replenishment: 7% BBOE Discovery costs $/BOE (9.6) Production (9.7) Asset sales 26. Additions exploration success rate 79% and resource adds.4 BBOE Low cost resource replacement Delivering projects Execution Hebron Increasing engineering maturity at FID Strengthening design assurance Optimizing contracting strategy Verifying execution readiness Improving quality management Start-ups Big Foot Stampede Sonam Mafumeira Sul Clair Ridge Gorgon Train 3 Wheatstone Competitor range: BP, RDS, TOT, XOM Start-up 206 net unrisked resource as defined in the Supplement to the Annual Report. 2 Source: Wood Mackenzie Company Exploration Benchmarking September

29 Diverse portfolio Maturity Resources New infrastructure Base business Geography Asset class 68 BBOE of 6P resource Permian TCO Heavy oil LNG Deepwater Shale & tight Gorgon Wheatstone Conventional Legacy assets Production operations 206 net unrisked resource as defined in the Supplement to the Annual Report. 29

30 Gorgon Strong performance (00% share) 2Q 207 average production ~333 MBOED Current production ~430 MBOED All LNG trains have achieved or exceeded nameplate capacity 4 wells producing ~3 BCFD Shipped 88 LNG cargos in 207 to date Focus areas moving forward Building reliability Fine tuning the process Debottlenecking As of July 28,

31 Wheatstone Train Platform operational Trunkline fully pressurized Early well results encouraging Plant starting-up Train 2 Construction on plan Start-up 6 8 months after Train As of July 28, 207 3

32 Australian gas position Carnarvon Basin Long-term cash generator North West Shelf Project Gorgon Project Optimization and debottlenecking of our 5.8 MMTPA capacity Perth 0 50 Wheatstone Project Monetize ~50 TCF* resource through equity or 3 rd party capacity Miles Greater Gorgon Wheatstone area NW Shelf Undeveloped Natural gas field *206 net unrisked resource as defined in the Supplement to the Annual Report. 32

33 Tengiz Base business Record production in 206 Outstanding reliability Strong earnings and cash generation Exceptional turnaround performance FGP / WPMP,2 Module fabrication in progress Dredging essentially complete Port on track for operation Site construction progressing 2 drilling rigs operating First production expected in 2022 Production profile Start-up in 2022 FGP Second generation plant WPMP Original plant FGP Future Growth Project; WPMP Wellhead Pressure Management Project 2 As of July 28,

34 Quality Permian acreage position Chevron acreage Chevron operated development Chevron non-operated development Updated acreage by NPV* (as of 2Q 207) >$50k / acre 650,000 <$20k / acre 400,000 $20k - $50k / acre 450,000 Total Midland & Delaware Acreage:.5 MM acres *NPV calculated assuming simultaneous development of all assessed benches (fully costed) across all acreage, using $50 WTI, $2.50 gas and $25 NGL real prices 34

35 Strategy of capital efficiency Improving performance through technology Seismic attribute assessment Petrophysical modeling Proprietary database for predictive analytics Data-driven completions optimization Precision lateral placement Integrated Operations Center Delaware Basin 2nd Bone Spring Average 6 month cumulative production (BOE/ft) Total Horizontal Well Count (200 Present) Competitor A Wells Competitor A Average Chevron Wells Chevron Average Delaware Basin Upper Avalon Shale Average 6 month cumulative production (BOE/ft) Total Horizontal Well Count (200 Present) IHS data (BOE / lateral foot), corrected for formation designation 2 Woodmac North America Well Analysis Tool Dataset: Delaware Basin horizontal wells ; omits data without well costs; $ / lateral foot; average lateral foot 4,000-5,000 Competitor A Wells Competitor A Average Chevron Wells Chevron Average Average Hz well cost for all competitors 2 : $,596/ft Average Hz well cost for Chevron 2 : $,522/ft 35

36 Permian unconventional financial performance Projected CVX unconventional Permian financial metrics $/BOE DD&A Lease operating expense Competitive development and direct lease operating costs $/BOE H $9 $3 H $6 $ Q 207 YTD Chevron Operated Non-Operated JV 207 Chevron Permian unconventional wells: 207 Chevron Permian Unconventional Wells : >30% IRR and 206 total costs per BOE are calculated as the sum of actual operating costs per BOE produced plus development costs per BOE expected ultimate recovery for wells put on production in 205 and actuals 3 Internal economics for 207 investments at $50 WTI, $2.50 gas and $25 NGL nominal prices 36

37 Active portfolio management to further unlock value Midland and Delaware Basin transaction activity Thousand acres Identified 50, ,000 acres to transact in 207 / 208 Closed 7 deals 2Q 207 YTD Acreage being marketed in multiple asset packages Completed transactions Forecast Transactions include acreage sales, swaps, joint ventures and farmouts 2 Majority of 205 / 206 completed transactions are asset sales 37

38 Permian support C H A V E S E D D Y L E A R O O S E V E L T C O C H R A N Y O A K U M G A I N E S A N D R E W S H O C K L E Y L U B B O C K T E R R Y LY N N Midland D A W S O N M A R T I N Cushing C R O S B Y G A R Z A B O R D E N H O W A R D D I C K E N S K E N T S C U R R Y M I T C H E L L Houston/ Export Supply Chain Leveraging global scale Staggered contract durations Indexed contracts L O V I N G W I N K L E R E C T O R M I D L A N D G L A S S C O C K S T E R L I N G C O K El Paso/CA C U L B E R S O N J E F F D A V I S 0 0 P R E S I D I O Miles Basin development R E E V E S B R E W S T E R W A R D Waha/Mexico C R A N E P E C O S U P T O N T E R R E L L R E A G A N C R O C K E T T I R I O N T O M G R E E N S C H L E I C H E S U T T O N Crude NGL Gas Katy Hub Mont Belvieu Fractionator Corpus Christi/ Export Infrastructure Secured takeaway capacity Multiple market outlets Expansion options 38

39 Permian production Midland and Delaware Basin Net MBOED ~20-35% CAGR Exceeding expectations 33% annual production growth company operated rigs Existing well declines Current design ~7 JV net rigs 3 Efficiency gains Actual production Reflects shale and tight production only; Upside cases not depicted in graph 2 Reflects growth between 2Q 206 and 2Q As of July 28,

40 Portfolio strength underpinned by base assets 207 base plus shale declines ~2% 2020 base* plus shale grows ~% Lower risk, short-cycle investments Diverse opportunities with new base assets Image: Kern River Field *Includes MCPs with first production / ramp-up and that fully ramp-up production by

41 Resources for the future Norway Barents Liard/ Horn River AOSP Low holding cost Midland & Delaware Basins Mexico DW Marcellus GOM DW Venezuela Nigeria Partitioned Zone Tengiz Thailand Options across geographies and five asset classes Total resource Heavy oil Deepwater LNG Shale & tight Angola Gorgon & Wheatstone Enabled by technology advances Conventional Exploration focus area New exploration area Significant resources within asset class net unrisked resource as defined in the Supplement of the Annual Report. 2 Represents the three largest resources by asset class. 4

42 Downstream & Chemicals

43 Downstream portfolio Fuels refining & marketing Integrated value chains Lubricants & additives Globally positioned Petrochemicals Advantaged feed and scale Steady growth, strong margins Low capital, high return Consistent cash generation Value chains Refinery Capital employed Major petrochemical complex.8 million barrels per day Refining capacity 8% 67% 5% 202 Refining & marketing Lubricants & additives Petrochemicals 25% 59% 6% million metric tons per annum Olefins capacity,2 3.3 million metric tons per annum Aromatics capacity,2 Chevron share of capacities. 2 Includes derivatives. 43

44 Strategy focused on leading returns Grow earnings across the value chain and make targeted investments to lead the industry in returns World-class operational excellence Drive earnings across the feedstock-to-customer value chain Targeted growth Create enterprise value 44

45 Fuels supply and demand Global products demand growth Compound annual growth rate Refinery net capacity additions MMBD LPG/Naphtha Distillate 6 4 Compound annual growth rate.0% 0.8% Gasoline 2 Fuel Oil -3% 0% 3% average projected average Global North America Rest of world Middle East Asia-Pacific Source: Wood Mackenzie 45

46 Value chains US West Coast Anchor markets: # brand share in Western U.S Latin America integration Optimization and integration: San Joaquin Valley equity crude Tightly integrated supply chain Largest West Coast base oil producer Leading retail network US Gulf Coast Anchor markets: Strong Gulf Coast / SE market position Leading brand in Central America Optimization and integration: GOM and Venezuelan equity crudes Top net cash margin refinery with fuels, base oil and petrochemicals Opportunity to integrate Permian Asia Pacific Anchor markets: Asia growth markets Legacy Caltex brand with long history Optimization and integration: World-class manufacturing, cross-regional optionality Long-standing partnerships Opportunity to strengthen refinery flexibility Pascagoula South Korea Richmond Equity crude El Segundo Salt Lake Equity crude Central America Thailand Hong Kong Malaysia Singapore Philippines To Central America Australia 46

47 Investing to strengthen the fuels value chain Richmond Refinery Modernization Improves safety, efficiency, reliability; reduces emissions Adds feedstock flexibility Projected start-up 208 Singapore Refining Co. Clean Mogas & Cogeneration Increases capability to produce higher-value gasoline Improves energy efficiency Projected start-up 207 Salt Lake Refinery Alkylation Retrofit Leverages ISOALKY technology Integrated catalyst regeneration Projected start-up

48 Chevron Phillips Chemical USGC petrochemicals project Overview,500 kmta ethylene, Cedar Bayou, Texas,000 kmta polyethylene, Old Ocean, Texas 500 kmta HDPE, 500 kmta LLDPE Advanced proprietary technology Progress Polyethylene, near mechanical completion Mid 207 projected start-up Ethylene, all mechanical equipment set Late 207 projected start-up Impact Increases CPChem ethylene and polyethylene capacity 30% As of March 7,

49 LNG outlook

50 Global LNG outlook Supply and demand MTPA 500 Emerging market demand growth continues 400 Supply opportunity Pacific Basin Intl. Under Construction U.S. Under Construction Europe to provide swing demand due to market access and flexibility 00 Pacific Basin Existing Atlantic Basin Atlantic Basin Demand Supply Future supply gap; new projects needed, low costs will be important Source: Wood Mackenzie 4Q6 50

51 Global LNG supply LNG supply MTPA Existing supply Australia leads current wave of supply growth U.S. underpins next wave Competition for supply opportunities will emerge Existing Australia US Other Source: Wood Mackenzie 4Q6 5

52 Gorgon & Wheatstone LNG customers Term LNG contract portfolio Spot Long term oil-linked contracts Term contract Increase in portfolio volumes provides flexibility Shipping provides access to total LNG value chain Source: CVX LNG contract volumetric obligations in