3Q 2015 Results and Investor Update

Transcription

1 3Q 2015 Results and Investor Update 27 October 2015 Thunder Horse, Gulf of Mexico

2 Jess Mitchell Head of Group Investor Relations PSVM, Angola

3 Cautionary statement Forward-looking statements - cautionary statement This presentation and the associated slides and discussion contain forward-looking statements that is, statements related to future, not past events with respect to the financial condition, results of operations and business of BP and certain of the expectations, intentions, plans and objectives of BP with respect to these items, in particular statements regarding future global energy trends and oil prices, including the prospect of future Iranian production; expectations regarding refining margins, seasonal demand, reported production and the unwinding of working capital in the fourth quarter; expectations regarding BP s share of Rosneft s production; expectations regarding the proposed Consent Decree, the timing of payments under the agreement and financial impact of the settlement on BP; expectations regarding BP s plans to rebalance the financial framework and the future growth of sustainable free cash flow and shareholder distributions over the long-term; plans and expectations regarding the Upstream major project pipeline and an increasing bias to gas over the next decade; expectations regarding Downstream future cash flows plans regarding the level of capital expenditure in 2017 and divestments through 2016 and thereafter; Upstream plans and expectations including lowering the managed decline of existing asset base, expected levels of in-year production, the allocation of capital, rate of return on projects and future development costs; plans to progress projects that meet certain criteria; the prospects for, expected timing, locations, composition and future production of major projects and growth beyond 2020; plans and expectations regarding competitive bidding programmes, third-party spend and Downstream efficiencies; plans and expectations regarding long-range cash generation, BP s ability to sustain its dividend and expected gearing levels; plans to take advantage of deflationary opportunities; and expectations regarding future organic growth and growth in free cash flow from By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including: the specific factors identified in the discussions accompanying such forward-looking statements; the receipt of relevant third party and/or regulatory approvals; the timing and level of maintenance and/or turnaround activity; the timing and volume of refinery additions and outages; the timing of bringing new fields onstream; the timing, quantum and nature of certain divestments; future levels of industry product supply, demand and pricing, including supply growth in North America; OPEC quota restrictions; PSA effects; operational and safety problems; potential lapses in product quality; economic and financial market conditions generally or in various countries and regions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; regulatory or legal actions including the types of enforcement action pursued and the nature of remedies sought or imposed; the actions of prosecutors, regulatory authorities and courts; the timing and amount of future payments relating to the Gulf of Mexico oil spill; exchange rate fluctuations; development and use of new technology; recruitment and retention of a skilled workforce; the success or otherwise of partnering; the actions of competitors, trading partners, contractors, subcontractors, creditors, rating agencies and others; our access to future credit resources; business disruption and crisis management; the impact on our reputation of ethical misconduct and non-compliance with regulatory obligations; trading losses; major uninsured losses; decisions by Rosneft s management and board of directors; the actions of contractors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism; cyber-attacks or sabotage; and other factors discussed under Principle risks and uncertainties in the results announcement for the period ended 30 June 2015 and Risk factors in BP Annual Report and Form 20-F 2014 as filed with the US Securities and Exchange Commission. This document contains references to non-proved resources and production outlooks based on non-proved resources that the SEC's rules prohibit us from including in our filings with the SEC. U.S. investors are urged to consider closely the disclosures in our Form 20-F, SEC File No This form is available on our website at You can also obtain this form from the SEC by calling SEC-0330 or by logging on to their website at Reconciliations to GAAP - This presentation also contains financial information which is not presented in accordance with generally accepted accounting principles (GAAP). A quantitative reconciliation of this information to the most directly comparable financial measure calculated and presented in accordance with GAAP can be found on our website at Tables and projections in this presentation are BP projections unless otherwise stated. October

4 Bob Dudley Group Chief Executive Deepsea Aberdeen drilling rig

5 Agenda 3Q 2015 results Our proposition for value growth A set of enduring principles A medium-term financial frame Our future Q&A 5

6 Brian Gilvary Chief Financial Officer Whiting refinery, Indiana

7 Environment Brent (1) Henry Hub (1) Refining Marker Margin (2) $/bbl $/mmbtu $/bbl (1) Source: Thomson Reuters Datastream (2) Refining Marker Margin based on BP s portfolio 7

8 3Q 2015 Summary Underlying earnings figures are adjusted for the costs associated with the Gulf of Mexico oil spill, other non-operating items and fair value accounting effects $bn 3Q14 2Q15 3Q15 % Y-o-Y % Q-o-Q Upstream Downstream Other businesses & corporate (0.3) (0.4) (0.2) Underlying business RCPBIT (1) (43)% 48% Rosneft (2) Consolidation adjustment - unrealised profit in inventory 0.4 (0.0) 0.1 (1) Replacement cost profit before interest and tax (RCPBIT) (2) 3Q15 represents BP estimate of Rosneft earnings after interest, tax and minority interest (3) Finance costs and net finance income or expense relating to pensions and other postretirement benefits (4) Operating cash flow is net cash provided by / (used in) operating activities Underlying RCPBIT (1) (40)% 38% Finance costs (3) (0.3) (0.4) (0.4) Tax (2.2) (0.7) (1.2) Minority interest (0.0) (0.0) (0.0) Underlying replacement cost profit (40)% 39% Underlying earnings per share (cents) (40)% 38% Dividend paid per share (cents) % 0% Operating cash flow (4) (45)% (18)% 8

9 Upstream (excluding Russia) 120 Realisations (1) Volume Underlying RCPBIT (2) 20 3, , $/bbl $/mcf mboed 2,500 2,250 2,000 $bn , Q14 4Q14 1Q15 2Q15 3Q15 Liquids $/bbl Gas $/mcf 0 1,500 3Q14 4Q14 1Q15 2Q15 3Q15 Total production excluding Russia -1 3Q14 4Q14 1Q15 2Q15 3Q15 Non-US US Total RCPBIT (1) Realisations based on sales of consolidated subsidiaries only, excluding equity-accounted entities (2) Replacement cost profit before interest and tax (RCPBIT), adjusted for non-operating items and fair value accounting effects 9

10 Downstream Refining environment Refining availability Underlying RCPBIT (1) $/bbl 12 % 92 $bn Q14 4Q14 1Q15 2Q15 3Q15 RMM WTI - WCS spread 86 3Q14 4Q14 1Q15 2Q15 3Q Q14 4Q14 1Q15 2Q15 3Q15 Fuels Lubricants Petrochemicals Total RCPBIT (1) Replacement cost profit before interest and tax (RCPBIT), adjusted for non-operating items and fair value accounting effects 10

11 Rosneft Average Urals price BP share of underlying net income (1) BP share of Rosneft dividend $/bbl 60 $bn 0.3 $bn Q14 4Q14 1Q15 2Q15 3Q Q14 4Q14 1Q15 2Q15 3Q Q14 4Q14 1Q15 2Q15 3Q15 (1) On a replacement cost basis and adjusted for non-operating items; 3Q15 represents BP estimate 11

12 Other items OB&C underlying RCPBIT (1) Underlying effective tax rate (2) 0.0 (0.1) 3Q14 4Q14 1Q15 2Q15 3Q15 (0.1) $bn (0.2) (0.2) % (0.3) (0.3) (0.3) 15 (0.4) (0.4) 10 5 (0.5) 0 3Q14 4Q14 1Q15 2Q15 3Q15 (1) Other businesses and corporate replacement cost profit before interest and tax (RCPBIT), adjusted for non-operating items. (2) 1Q15 adjusted to remove one-off deferred tax benefit from the reduction in the rate of the supplementary charge in the UK. 12

13 Gulf of Mexico oil spill costs and provisions pre-tax (1) $bn Income statement To end H Q 2015 Cumulative to date Charge / (credit) for the period Balance sheet (2) Brought forward Charge / (credit) to income statement Payments into Trust Fund (20.0) - - (20.0) Cash settlements received Other related payments in the period (3) (20.9) (0.8) (0.2) (21.9) Carried forward Cash outflow (1) Includes contributions received from Mitsui, Weatherford, Anadarko and Cameron (2) Balance sheet amount includes all provisions, other payables and the asset balances related to the Gulf of Mexico oil spill (3) Please refer to details as disclosed in the third-quarter Stock Exchange Announcement 13

14 Sources and uses of cash YTD 2014 YTD Disposals 25 Gulf of Mexico oil spill 25 Share buybacks 20 Dividends 20 - Gulf of Mexico oil spill $bn 15 Underlying cash flow (1) Inorganic capex $bn 15 Disposals Dividends Inorganic capex 10 5 Organic capex 10 5 Underlying cash flow (1) Organic capex 0 Sources Uses 0 Sources Uses (1) Underlying cash flow reflects operating cash flow excluding Gulf of Mexico oil spill pre-tax cash flows 14

15 Bob Dudley Group Chief Executive Cassia, Trinidad

16 A new price environment Forward strip June 2014 Dated Brent $/bbl Forward strip February Forward strip October Source: Platts; forward strip prices represent Intercontinental Exchange Brent Crude Oil futures 16

17 Our proposition for value growth A clear set of enduring principles Relentless focus on safety and reliability A balanced portfolio with distinctive capabilities Portfolio actively managed for value over volume Continued capital and cost discipline Growing sustainable free cash flow and distributions over the long term 17

18 Relentless focus on safety and reliability Upstream (1) Downstream Tier 1 events 15 BP operated plant reliability % 95 Tier 1 events 50 Solomon availability % YTD 1H YTD 2015 (1) Excluding Lower 48 18

19 A balanced portfolio Resilient to the environment Integrated business model ~1/3 of Upstream production from Production Sharing Agreements ~80% of pre-fid (1) major projects break-even below $60/bbl Brent oil price Long-term growth and optionality Upstream Balance of deepwater, gas value chains and giant fields, with an increasing bias to gas Strong pipeline of growth options Downstream Advantaged manufacturing and marketing growth Contribution to 2020 pre-tax operating cash flow (2) Pre-FID (2) Post-FID (2) major projects Existing assets Marketing Manufacturing Upstream Gas value chains Deepwater oil Giant oil fields Downstream Other Azerbaijan Angola North Sea Gulf of Mexico Growth Markets Mature Markets (1) Final Investment Decision (2) Based on BP planning assumptions 19

20 Actively managing our portfolio for value over volume Optimising the portfolio for shareholder value Divesting assets that no longer compete Divestments Acquisitions Selective acquisition to add value Creating innovative new business models Disciplined and timely allocation of capital Playing to our strengths Upstream and Downstream Balancing pace to capture deflation Preserving future growth objectives Portfolio of opportunities Organic capital expenditure Capital expenditure Upstream RISK Downstream /other Total Group 2014 $19.0bn $3.9bn $22.9bn RETURNS 2015 to 2017 $15bn to $16bn $2bn to $3bn $17bn to $19bn 20

21 Upstream: a resilient base and disciplined growth Improving safety and reliability Maximising production from existing assets High-quality project pipeline underpinning growth Disciplined investment for growth Resetting the cost base 21

22 Resilient base performance Managing field decline (1) NPT 35% Non-productive time and wells completed (3) Wells 150 Managed decline trend (1) ~2% FY est. 100 mmboed 30% % Base 2015/16 Project start-ups PSA (2) impacts Wells completed Non-productive time (NPT) 2015 represents YTD (1) Managed base comprises all assets onstream at 31 December 2014 (2) Production sharing agreement (3) Excludes US Lower 48 Source: BP estimates 22

23 Upstream capital optimisation Expected capital spend 2015 to 2018 Disciplined investment approach Projects Capital allocation process aligned with strategy Exploration New wells & wellwork Competitive returns Uncommitted spend provides flexibility Base integrity & other 23

24 Improving quality of future investments Progression only when value thresholds are met Delivering value improvements Renegotiate supply chain contracts Standardisation Using industry led solutions Optimising scope and phasing Focus on front-end loading Focus on value growth versus volume Brent $/boe Break-even price for BP s pre-fid major projects (1) October 2015 estimate October 2014 estimate Industry Average $40 65 /boe (1) Based on BP planning assumptions; excludes Russia and US Lower 48. Industry average source: Wood Mac Point forward capital spend $bn 24

25 Improving quality of future investments - examples Phasing optimisation West Nile Delta Capital Expenditure Scope and cost optimisation Thunder Horse South Expansion Capex reduced; first gas delivery unchanged -21% +10% Capex Production Source: BP internal data 3Q 2014 plan 3Q 2015 plan 25

26 Our robust growth option hopper Net production from new major projects (1) 1,000 By resource type 1,000 By project stage Conventional oil Appraise 750 Deepwater oil 750 Heavy oil Design mboed 500 Conventional gas mboed Tight gas 250 Construction LNG start-ups startups 2014 start-ups ups Operating (1) (1) Production from 2014 major project start-ups now reported within managed base 26

27 Our project pipeline Operating and construction 2014 to 2018 Start-up Project Location Type WI % Plateau (1) Operator Devt stage 2014 Chirag Oil Azerbaijan Conventional oil BP Operating Mars B GoM Deepwater oil Shell Operating NaKika Phase 3 GoM Deepwater oil BP Operating Atlantis North Expansion Ph 2 GoM Deepwater oil BP Operating CLOV Angola Deepwater oil Total Operating Sunrise Phase 1 Canada Heavy Oil Husky Operating Kinnoull N Sea Conventional oil BP Operating 2015 Kiz Satellites Phase 2 Angola Deepwater oil Exxon Operating Greater Plutonio Phase 3 Angola Deepwater oil BP Operating Western Flank A AsiaPac LNG Woodside Operating In Salah Southern Fields N Africa Conventional gas JV Construction 2016 Angola LNG Angola LNG JV Construction In Amenas Compression N Africa Conventional gas JV Construction Point Thomson Alaska Conventional gas 32 8 Exxon Construction Quad 204 N Sea Conventional oil BP Construction Thunder Horse Water injection GoM Deepwater oil BP Construction 2017 Clair Ridge N Sea Conventional oil BP Construction Juniper Trinidad LNG bptt Construction Oman Khazzan Middle East Tight Gas BP Construction Persephone AsiaPac LNG Woodside Construction Thunder Horse South Expansion GoM Deepwater oil BP Construction West Nile Delta T/L Egypt Conventional gas BP Construction Culzean N Sea High pressure gas Maersk Construction Shah Deniz Phase 2 Azerbaijan Conventional gas BP Construction Design and appraise 2017 to 2020 Start-up Project Location Type Angelin Trinidad LNG Atoll Egypt Conventional gas B18 Platina Angola Deepwater oil Mad Dog Phase 2 GoM Deepwater oil Pike Phase 1 Canada Heavy Oil Snadd N Sea Conventional gas Tangguh Expansion AsiaPac LNG Trinidad Onshore Compression Trinidad LNG Trinidad Offshore Compression Trinidad LNG Vorlich N Sea Conventional oil West Nile Delta G/F/R Egypt Conventional gas Western Flank B AsiaPac LNG Additional projects in the pipeline for post-2020 start-up or nearer-term optimisation (1) Gross production mboed 27

28 Growth beyond 2020 Alaska Drill out 3 hubs Alaska LNG Canada Sunrise later phases Pike, multiple phases Terre de Grace Eastern Canada exploration GoM Drill out 7 Hubs Paleogene Exploration drill out BP resources (ex. Russia) Proved Lower bn bbls resources. 5.7 million acres Conventional oil Deepwater oil Conventional gas Unconventional Trinidad Develop discovered new fields Exploration drill out Brazil Itaipu/Wahoo Exploration drill out Argentina (PAE) Cerro Dragon Neuquen basin Mexico Round 1 North Sea Drill out 10 Hubs Greater Clair Exploration drill out North Africa Gulf of Suez drill out Algeria drill out END & WND follow on Mediterranean exploration Angola Drill out 5 blocks Block 31 Projects Exploration drill out AGT ACG drill out and next Platforms Azerbaijan Exploration- Shah Deniz Deep, Shafag Asiman, Shallow Water Absheron Peninsula Middle East Oman drill out Rumaila development Access options Russia Taas JV (Srednebotuobinskoye) Yenisey-Khatanga development and exploration West Siberian exploration Asia Pacific India Projects Browse Australia exploration Non-Proved Source: BP estimates year ended 31 December

29 Upstream focus on costs Right-size the organisation Reduce third party spend 14 Production Cost Deflation across contracts Efficiency of scope and delivery Influence partner operated spend $/boe No compromise on safety est. 29

30 New Lower 48 model starting to deliver Material resource base bn boe Focus on safety, innovation and performance Improvements in cost and capital efficiency Unit cash costs down ~18% Innovative well design and execution Competitive and improving returns 5.7m net acres Contingent Proved and probable 7.5bn boe resource Active evaluation of portfolio Reinvigorate underworked acreage Selective inorganic activity Source: BP internal data year ended 31 Dec

31 New Lower 48 model: improving capital efficiency Well development costs versus peers by play 10 North West MidCon (Granite Wash) MidCon (Woodford) 50 East $/boe BP operated Previous BP operated wells Indicative competitor range 31

32 Downstream: focused on performance and growth Pre-tax returns % Strong underlying performance improvement with attractive returns Actual returns Resilient and growing delivery Quality portfolio Margin Margin adjusted adjusted (1) returns (1) Advantaged manufacturing Q 2015 (2) Net income per barrel Marketing growth 10 BP Simplification and efficiency $/bbl Competitor range (1) Margin adjusted returns calculated using 2014 Refining Marker Margin of $14.4/bbl (2) rolling 4 quarters to 3Q 2015; 2013 and 2014 annual data Q 2015 (2) 32

33 Downstream strategy Advantaged manufacturing Top quartile refining Competitively advantaged portfolio Improved petrochemicals profit potential Marketing growth Reliable profit and cash generation Growth markets access Differentiated products and customer focus Leading technology 33

34 Downstream focus on costs Continued year-on-year cash cost reduction Cash costs-to-gross margin ratio (1) Right-sizing the organisation Simplified business model and portfolio Streamlining head office activities and functions Manufacturing efficiency Reduction in third party spend YTD 2015 (1) Further details available in supplementary information 34

35 A unique position in Russia 25 years experience in Russia Strong relationships Strategic partnership with Rosneft 19.75% shareholding; 2 board members Efficient operations, world-class projects and resilient financial performance BP projects in Russia 20% share of Taas-Yuriakh development Word-class exploration Areas of Mutual Interest (AMI) in Eastern and Western Siberia Volga-Urals exploration Joint Venture Baikalovskoye JV BP share of Rosneft BP Upstream BP total Taas AMI Production (1) mmboed Proved reserves (2) bn boe Volga-Urals AMI West Siberia AMIs Taas JV (1) Year ending 31 December 2014 (2) At 31 December

36 Our proposition for value growth A clear set of enduring principles Relentless focus on safety and reliability A balanced portfolio with distinctive capabilities Portfolio actively managed for value over volume Continued capital and cost discipline Growing sustainable free cash flow and distributions over the long term 36

37 Brian Gilvary Chief Financial Officer Arboles, US Lower 48

38 A medium-term financial frame 1. Capex of $17-19bn per annum over Cash costs reduced by over $6bn by 2017 versus Balance organic sources and uses of cash (1) at ~$60/bbl by 2017; organic free cash flow growth thereafter 4. Divestments of $9-10bn ; $3-5bn 2016; $2-3bn Gearing managed with flexibility around 20% 6. Commitment to sustaining the dividend (1) Excludes Deepwater Horizon (DWH) payments, includes 100% of dividend. Organic free cashflow = Operating cash flow excluding DWH payments less organic capex. 38

39 Capital discipline Phasing and optimising activity Disciplined Upstream investment Selective growth investments in Downstream and other businesses Capturing deflation and driving capital efficiency Capex of $17-19bn per annum over $bn Capital framework

40 Resetting cash costs Right-sizing of cost base to smaller footprint Group-wide simplification and efficiency Group cash costs (1) $bn >$6bn Restructuring charge to approach $2.5bn by end-2016 Cash costs reduced by over $6bn by 2017 versus 2014 (1) (1) Cash costs are the principal operating and overhead costs that management considers to be most directly under their control. See bp.com for further information 40

41 Organic free cash flow growth Cost reset creates a more efficient platform Leveraged to Continuous Upstream organic growth and price upside Downstream efficiency and growth Capacity to restore growth in distributions US cents per share Organic free cash flow per share (1) Brent price (real) $60/bbl $70/bbl Current dividend per share (1) Based on: $3 mmbtu Henry Hub gas (real) and $15/bbl Refining Marker Margin Excludes Deepwater Horizon (DWH) payments, includes 100% of dividend. Organic free cashflow = Operating cash flow excluding DWH payments less organic capex. 41

42 Divestments Divestments since 2010 Targeted divestments Now approaching $75bn since 2010 including the sale of BP s interest in TNK-BP $9-10bn over $bn TNK-BP $27.5 $bn 12 8 $9-10bn $3-5bn expected in $3-5bn Ongoing $2-3bn per annum to date $2-3bn

43 Balance sheet resilience 10-20% gearing band put in place in 2010 to manage uncertainty Greater clarity on Deepwater Horizon commitments % % Gearing 10-20% Gearing managed with flexibility around the 20% level going forward

44 Bob Dudley Group Chief Executive

45 Our future A clear set of enduring principles Relentless focus on safety and reliability A balanced portfolio with distinctive capabilities Portfolio actively managed for value over volume Continued capital and cost discipline Growing sustainable free cash flow and distributions over the long term A medium-term financial frame Capex of $17-19bn per annum over Cash costs reduced by over $6bn by 2017 versus 2014 Balance organic sources and uses of cash (1) at ~$60/bbl by 2017; organic free cash flow growth thereafter Divestments of $9-10bn ; $3-5bn 2016; $2-3bn Gearing managed with flexibility around 20% Commitment to sustaining the dividend (1) Excludes DWH payments, includes 100% of dividend. Organic free cashflow = Operating cash flow excluding Deepwater Horizon payments less organic capex.

46 Q&A Bob Dudley Group Chief Executive Brian Gilvary Chief Financial Officer Lamar McKay Chief Executive, Upstream Tufan Erginbilgic Chief Executive, Downstream Jess Mitchell Head of Group Investor Relations 46