Recommended
More Related Content
What's hot
What's hot (20)
Similar to Premier oil inv_pres_nov_2015
Similar to Premier oil inv_pres_nov_2015 (20)
More from Company Spotlight
More from Company Spotlight (20)
Recently uploaded
Recently uploaded (8)
Premier oil inv_pres_nov_2015
- 2. Forward looking statements This presentation may contain forward-looking statements and information that both represents management's current expectations or beliefs concerning future events and are subject to known and unknown risks and uncertainties. A number of factors could cause actual results, performance or events to differ materially from those expressed or implied by these forward-looking statements. November2015 | P1
- 4. Delivering our short term targets Above budget and guidance year-to-date driven by 90% operating efficiency Strong operating cash flow Production of 57.5 kboepd Opex per barrel reduction Net debt stable Covenant flexibility Solan and Catcher milestones achieved Resource additions Increased cash flows: strong production, lower costs and hedging benefits (which continue for rest of 2015 and 2016) Further cost savings identified; $16/boe opex expected for FY2015 Net debt of $2.3 billion, despite ongoing investments in Solan and Catcher Renegotiated terms; covenant headroom >$700m for FY2015 On track for first oil before the year end from Solan and 2017 from Catcher Discoveries atZebedee and Isobel Deep; resource additions at Anoa Refocusing the portfolio Asset disposals (Norway subsidiary andAceh in Indonesia); Low cost acreage additions in Brazil and Mexico November 2015 | P3
- 5. Cash generation in a low oil price environment November 2015 | P4 • Growing production profile – Intense focus on execution – Reducing level of spend 2. • Robust, low cost production generates good cash flow 1. • Free cash flow will be directed at debt reduction 3. 20 19 17 14 16 0 5 10 15 20 2013 2014 2015 budget 2015 1H 2015 forecast Opex ($/boe) Committed capex $m 0 200 400 600 800 1000 1200 2015F 2016 2017 2018 Exploration P&D Capex
- 6. Favourable financing structure November 2015 | P5 • Liquidity – $1.2bn cash & undrawn facilities (end October 2015) – No significant debt maturities until 2019 2. • Corporate unsecured structure – No reserve base redeterminations – Average debt cost 2015 ytd: 3.5% 1. • Increased financial flexibility – Covenants amended – Strong support from banks & bondholders 3. Net debt/ EBITDAX Old covenants Amended covenants 0 1 2 3 4 5 2015 1H 2015 FY 2016 1H 2016 FY 2017 1H 2017 FY 307 362 1,238 558 0 200 400 600 800 1000 1200 1400 2015 2016 2017 2018 2019 2020- 2024 Drawn debt maturities ($m)
- 7. Production
- 8. Pakistan (10.3 kboepd) • Well-established gas producing fields • Generates positive, stable cash flows • Formal sales process ongoing 0 5 10 15 20 2014 2015 ytd 2015 ytd – strong production November 2015 | P7 Indonesia (13.8 kboepd) • Singapore demand above take or pay • GSA1 share 42.8%; above contractual share of 39.9% • Pelikan on-stream 0 5 10 15 20 2014 2015 ytd Vietnam (17.0 kboepd) • High operating efficiency following summer shutdown • Better than predicted reservoir performance 0 5 10 15 20 2014 2015 ytd Group • High operating efficiency • Higher liquids production 0 10 20 30 40 50 60 70 2014 2015 ytd FY guidance 2015 ytd average: 57.5 kboepd North Sea (16.4 kboepd) • Unrestricted production from Huntington since April • Steady production from rest of UK portfolio 0 5 10 15 20 25 2014 2015 ytd OE 84% OE 90% OE 72% Production (kboepd)Production (kboepd) Production (kboepd)Production (kboepd) OE 87% OE 84% OE 86% OE 94% OE 92% OE 96% OE 95%
- 9. UK – underlying growth 2015 ytd • Averaged 16.4 kboepd • Improved operating efficiency • Opex $30.2/bbl, down 20% (FY 2014: $37.75/bbl) – Sale of high cost Scott area – Active cost management and G&A cuts • Sanctioned projects will see Premier’s UK production rise to c. 50 kboepd • $3.3 bn of UK tax losses and allowances Catcher Balmoral AreaSolan Wytch Farm Kyle Huntington 87% operating efficiency Key projects Equity interest First oil/gas Operator Reserves YE14 (gross) Balmoral Area c. 80% Various Premier 7 mmboe Catcher 50% 2017 Premier 96 mmboe Huntington 40% 2013 E.On 16 mmboe Kyle 40% 2001 CNR 5 mmboe Solan 100% 2015 Premier 44 mmboe Wytch Farm 30% 1979 Perenco 47 mmboe November 2015 | P8
- 10. Indonesia – strategically positioned 2015 ytd highlights •Singapore demand aboveToP •42.8% of GSA1 vs 39.9% contractual share •Pelikan on-stream •Block A Aceh sale completed Outlook •Steady Singapore gas demand but increasing market share for GSA1 •Portfolio of growth opportunities GSA2 Domestic Gas Swap GSA1 November 2015 | P9 42.8% share of GSA1 Growing domestic market
- 11. Vietnam – high performing cash generator November 2015 | P10 2015 ytd highlights • 17 kboepd, reflecting continued outperformance • Better than predicted reservoir performance • Significantly reduced opex at c.$12/boe • 5% premium to Brent for crude Outlook • No committed capex • Incremental growth opportunities 0 5 10 15 2017 2018 2019 2020 2021 2022 2023 Incremental production 86% operating efficiency
- 12. Development
- 13. Development – sustained growth Catcher (50% op.) • 96 mmboe • ~50 kbopd at peak • $1.6bn capex pre-first oil • Reservoir upside Solan (100% op.) • >40 mmbbls • First oil stillQ4 2015 • $1.76bn capex spent to endOct 2015 BIGP (28.7% op.) • Backfill our existing contracts • Q4 2016 investment decision Sea Lion Phase 1a (60% op.) • c. 160 mmbbls • ~60 kbopd • $1.8bn capex pre-first oil • 2016 FEED decision Increasing deliverability November 2015 | P12 Monetising high value UK tax pool Progressing phased, lower capex solution Monetising high value UK tax pool
- 14. Solan – first oil Q4 2015 Long term vision • Reserves upside potential • Infill drilling opportunities; near field exploration • Nearby accumulations; potential 3rd party business over Solan hub facility • Consider farm down of equity post first oil Cash generative $26/bbl opex (LOF) No tax 25,000 20,000 15,000 10,000 5,000 0 2020 Solan oil production rate (stb/d) November 2015 | P13 Potential ullage? 2015 ytd highlights • P1/W2 tied in; P2 suspended, W2 underway • Improved offshore productivity • Removed partner funding concerns • Reduced balance sheet exposure (Flowstream) • Cash spend at as 31 Oct $1.76m Peak production 25,000 bopd
- 15. Solan – facilities update 2015 1H Sep - Oct Nov - Dec Siem Spearfish 60 men; 180-280 hrs/day Regalia flotel 135-150 men; 600-800 hrs/day Superior flotel 200-240 men; 1,000 hrs/day Habitation 20 men; 100-120 hrs/day Complete construction works; commissioning of accommodation Commissioning of safety, accommodation, & production systems, power generation & utilities Tanker Offloading trials Jul - Aug Bibby DSV SOST & P1/W1 tied in Ocean Valiant P2 suspended; sidetrack Q2 2016 Victory 250 men; 800-1,000 hrs/day Completion of over-side work & commissioning of emergency power systems Bibby DSV Complete commissioning of subsea infrastructure o Ocean Valiant W2 spudded Commissioning of production systems Commissioning of production systems First oil November 2015 | P14
- 16. November 2015| P15 Catcher area Reservoir upside Near field tie-backs Exploration upside No tax Catcher 5P, 2I Varadero 4P, 3I Burgman 5P, 3I
- 17. Catcher – subsea • 2 templates installed (Catcher 1 & Burgman 1) • PLEM installed • 60 km gas export pipeline lay completed • Fabrication of remaining templates completed • Fabrication of towheads well-advanced • First steel cut on mid- water arches • Fabrication of bundles underway • Fabrication of risers and jumpers to commence in 2016 November 2015 | P16
- 18. Catcher - execution phase progressing November 2015 | P17 Formal concept select FPSO HUC DECC approval 2013 201620152014 2017 Exploration FPSO and SURF fabrication commenced SURF installation Development drilling FPSO • Turret and mooring system progressing • Hull fabrication on-going in Japan and Korea • Topsides fabrication underway in ProFab, Dynamac and Asia Offshore yards Drilling • Ensco 100 rig on hire since July • Batch drilling of first 4 wells completed • CTI1 water injection well complete; good reservoir results • CCI2 water injection well being completed • Operations on schedule and within budget 96mmboe $1.6bn (gross budget to first oil) Peak production c.50 kbopd First oil CTI1 Buoy and moorings installation
- 19. De-risking the Sea Lion development November 2015 | P18 • Phase 1a reservoir is fully appraised, subsurface plan is robust • FPSO and SURF is well understood, conceptual design is now mature • Key project execution contractors selected ahead of FEED • Financing plans progressing well • Upside in the area has increased and become better defined • Stakeholder discussions continuing
- 20. Phase 1a facilities Subsea drill centre FPSOShuttle tanker 8 well production manifold 5 well water injection manifold Flowline to gas well Nov 2014 capex Pre-sanction capex $0.1bn Surf & installation $0.7bn Project management $0.4bn Pre-first oil drillex $0.6bn $1.8bn Potential for cost reductions November 2015 | P19 3Km Phase 1a (160 mmbbls) Phase 1b Phase 2
- 21. Exploration
- 22. Exploration – re-shaping the portfolio Balance of wells targeting Mature verses Emerging plays 2012 2015 North Sea and SE Asia Falklands, Brazil and Mexico 110 Growth in emerging basins with material opportunities Rationalisation in mature areas • Focusing on under-explored, emerging plays in proven hydrocarbon provinces – Entry into Brazil and follow-on farm in to Block 661, Ceará Basin – Successful entry into Mexico with award of Blocks 2 & 7 • Minimising up-front capex commitments • Current industry conditions favour low cost acreage acquisition • Exiting acreage in traditional, more mature areas (save for near-field exploration) – Significant disposal proceeds and reduced well commitments – Improved materiality of discoveries • Net unrisked prospective resource of >1 bn boe 100% Emerging 100% Mature 2015 well campaign 2012 well campaign 1751 November 2015 | P21
- 23. 2015 North Falklands Basin campaign 2015 ytd highlights • Zebedee oil & gas discovery (36% op interest) – adds c. 50 mmbbls to Phase 2 • Isobel Deep oil discovery (36% op interest) – de-risks the Isobel/Elaine fan complex (un- risked Pmean resource of 400 mmbbls) – opens up potential Phase 3 development Two discoveries from two wells 2015 /2016 look ahead • Isobel Deep (36% op interest), well to spudQ4 2015 – Partners agreed to performing more drilling at Isobel Deep, ahead of Jayne East • Chatham (40% op interest), well to spudQ1 2016 – would add resource to Phase 1b Chatham Pmean 47 mmbbls 50 mmbls Zebedee Southern exploration leads Phase 2 prospects PL032 prospects Jayne East Pmean 39mmbbls Isobel / Elaine Pmean 400 mmbbls November 2015 | P22 Beyond 2016 • Additional exploration/appraisal prospects identified for drilling in 2017/2018
- 24. Falklands: Isobel Deep Re-Drill Full stack amplitude at F3G horizon • Further drilling at Isobel / Elaine complex to confirm significant resource potential of southern F3 fan system (unrisked Pmean 400 mmbbls) • Chatham exploration well follows, also appraises the expected gas cap in the west of the Sea Lion field • North Falkland Graben Isobel / Elaine Re-drill Isobel Deep Jayne East Zebedee Jayne East Isobel Deep Isobel / Elaine November 2015 | P23 10Km
- 25. Brazil Ceará Basin – expanding acreage footprint Pecem discovery • Flowed light oil to surface when tested in 2014 • De-risks key play elements Outline of new 3D survey being acquired 2H15 Cretaceous sand channel systems Brazil Focus Basin • Strong analogies with West African Tano basin discoveries • Proven light oil petroleum system • Multiple play types • Attracted supermajors to make significant operational commitments Opportunity • Position in 3 Licences provides dominant position in basin • 3 wells drilling late 2017/18 • Premier coordinating rig- share • 3D seismic survey 50% complete Mean gross unrisked resource > 2 bn bbls November 2015 | P24
- 26. Mexico – low cost entry Strong partnership Proven but under-explored hydrocarbon basin Low cost entry November 2015 | P25 Block 2 • Primary target – 100 mmbbls • 3 follow on prospects of c. 80-100 mmbbls each Block 7 • Primary target – 130 mmbbls • 4 follow on prospects of c. 40-150 mmbbls each Block 2 Salt stock Closure Miocene Depth Structure Map – Poblano Prospect Low cost entry to high quality acreage • Awarded 10% in Blocks 2 & 7, shallow water Sureste Basin • Option to increase interest to 25% prior to drilling • Numerous leads in established and emerging plays • Fully carried to first well on each block
- 27. 2015/2016 exploration drilling schedule November 2015 | P26 All well timings are subject to revision for operational reasons
- 28. Finance
- 29. Strong cash flows in 2015 1H 6 months to 30 June 2015 6 months to 30 June 2014 Working Interest production (kboepd) 60.4 64.9 Entitlement production (kboepd) 55.7 59.7 Realised oil price (US$/bbl) - post hedge 83.7 107.9 Realised gas price (US$/mcf) - post hedge 7.2 9.1 $m $m Cash flow from operations 570 609 Taxation (57) (110) Operating cash flow 513 499 Capital expenditure (518) (506) Disposals 83 - Finance and other charges, net (49) (49) Dividends - (44) Share buy back - (33) Net cash in (out) flow 29 (236) Capital expenditure ($m) Comprises $49m from the BlockAAceh sale and ~$34m positive adjustment from Scott area disposal Liquids hedging 1H 2015 2H 2015 2016 Barrels hedged 2.7 m 2.85 m 3.65 m Average price ($/bbl) $103 $92 $68 2015 1H FY 2015 E Exploration $115 $240 Development $403 $900 Total $518 $1,140 November2015 | P28
- 30. 0 500 1000 1500 2014 2015F 2016 2017 2018 Committed capex ($m) Exploration P&D Capex Significantly reduced costs November 2015 | P29 30% reduction in opex • Sale of Scott area • Renegotiation of contracts • Operating efficiencies • Lower insurance & fuel costs • Reduced headcount • Contractor rate cuts 0 100 200 300 400 500 FY 2014 (actual) 2015 initial budget (Oct 14) 2015 final budget (Feb 15) 2015 forecast (Aug 15) Opex ($m) 0 50 100 150 200 250 300 350 FY 2014 (actual) 2015 initial budget (Oct 14) 2015 final budget (Feb 15) 2015 forecast (Aug 15) Gross G&A ($m) 2015 1H: $14/bbl opex Significantly reduced capex commitments from 2016 Forecast Actual Forecast Actual
- 31. 6 months to 30 June 2015 $m 6 months to 30 June 2014 $m Sales and other operating revenues 577 885 Cost of sales (684) (646) Gross profit/(loss) (107) 239 Exploration/New Business (52) (50) General and administration costs (8) (13) Disposals - (84) Operating profit/(loss) (167) 92 Financial items (48) (41) Profit/(loss) before taxation (215) 51 Tax credit/(charge) (160) 122 Profit/(loss) after taxation (375) 173 Income statement Operating costs ($/boe) * excludes insurance receipts of $4.7m Cost of sales breakdown 2015 1H 2014 1H UK $28.8 $34.9 Indonesia $8.9 $10.1 Pakistan $3.2 $2.7 Vietnam $10.1* $15.5 Group $13.7 $18.5 Profit before tax and impairments 171 195 November 2015 | P30 0 250 500 750 Operating costs Stock underlift Royalties DD&A Impair- ment Cost of sales Non-cash items $3.3 bn of UK tax losses and allowances
- 32. Liquidity and balance sheet position At 30 June 2015 $m At 31 Dec 2014 $m Cash 372 292 Bank debt (1,482) (1,230) Bonds (753) (955) Convertibles1 (230) (229) Net debt position (2,093) (2,122) Covenant headroom $417 $700 Gearing2 59% 53% Cash and undrawn facilities 1,446 1,940 1 Maturity value of US$245 million 2 Net debt/net debt plus equity Average debt costs of 4.7% (fixed) and 2.2% (floating) Net debt/ EBITDAX Old covenants Amended covenants November 2015 | P31 307 362 1238 558 0 200 400 600 800 1000 1200 1400 2015 2016 2017 2018 2019 2020- 2024 Drawn debt maturities ($m) 0 1 2 3 4 5 2015 1H 2015 FY 2016 1H 2016 FY 2017 1H 2017 FY
- 33. End 2014 2P reserves and resources November 2015 | P32 Falklands Indonesia Mauritania Norway Pakistan UK Vietnam Total 2P On Production – 33.7 0.4 – 16.3 26.5 26.0 102.8 Approved for Development – 10.5 – – – 74.2 1.4 86.1 Justified for Development – 29.1 – 23.2 – 2.2 – 54.4 Total Reserves – 73.3 0.4 23.2 16.3 102.8 27.3 243.3 2C Development Pending 98.0 – 3.1 37.5 0.6 0.1 – 139.3 Development Unclarified / on hold 142.0 170.8 3.6 5.1 3.0 16.9 7.4 348.7 Development not viable 33.8 4.5 1.3 2.4 – 18.2 2.2 62.4 TotalContingent Resources 273.7 175.4 8.0 45.0 3.6 35.1 9.6 550.5 Total Reserves + Contingent Resources 273.7 248.7 8.4 68.2 19.9 137.9 36.9 793.8
- 34. Premier Oil Plc 23 Lower Belgrave Street London SW1W 0NR Tel: +44 (0)20 7730 1111 Fax: +44 (0)20 7730 4696 Email: premier@premier-oil.com www.premier-oil.com November 2015