Premier Oil Investor Presentation 2017-February
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Premier Oil Investor Presentation 2017-02-17, 2016 Highlights - High Operating Efficiency, Step Change in Production, Continued Portfolio Upgrading, Cost Reductions, Refinancing in Progress.
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Premier Oil Investor Presentation 2017-February
- 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. February 2017 | P1
- 3. Cost reductions delivered High operating efficiency Step change in production Continued portfolio upgrading Refinancing in progress 2016 highlights 1 2 3 4 5 2016 2017E 91% >90% 2015 2016 2016 Q4 58 kboepd 71.kboepd >80 kboepd E.ON acquisition case 2016 2H 15 kboepd 17 kboepd 2014 opex 2016 opex $18.5/boe $15.7/boe Drawn Debt Total Facilities (incl LCs) $3.4 bn $4 bn Undrawn February 2017 | P2
- 4. Indonesia • >90% operating efficiency • Strong demand (44% of GSA 1, record GSA 2 delivery) • $10/boe opex • Increase demand post 2020 – Quick payback, high return projects – Bison, Iguana, Gajah Puteri • Longer term growth opportunities – Tuna, 3rd party business Asia – providing cash flow for the business Vietnam • >90% operating efficiency • <$9/boe opex • Further cost reductions – Renegotiation of vessel and helicopter contracts – Revised terms for FPSO agreed • High return, low cost projects include infill drilling in 2017 Low cost, high return opportunities to maintain / grow production February 2017 | P3
- 5. UK North Sea – growth story Wytch Farm (30.1%) • Long life field • Infill opportunities Solan (100% op) • Production currently restricted at 10-13 kbopd • Cost reductions continue to be secured UK overview • Improved uptime • UK drives production growth: • Strong operating base • Tax advantaged position Babbage (47%) • High uptime • Moving to unmanned • Cobra potential tie-back Elgin-Franklin (5.2%) • Long life field • Rates of >130 kboepd (gross) • On-going infill drilling and well intervention programme Huntington (100% op) • Strong reservoir performance • 2016 production significantly above budget Catcher (50% op) • On track for first oil 2017 • 29% cost reduction secured Tolmount (50% op) • Low cost, high return project • Significant area upside • Tolmount East +250 bcf • Tolmount Far East +150 bcf February 2017 | P4 2015A 2016A 2017E 2018E UK production
- 6. • Templates, flowline bundles, midwater arches and gas export pipeline installed • Buoy and moorings system installed • Hook up of risers & umbilicals completed • Subsea programme below budget Subsea • 9 wells drilled with excellent operational performance • Pre-drill predictions for reservoir quality and flow rates at or above prognosis • Drilling programme below budget Catcher – ahead of plan Burgman BP3 producer well Tay reservoir Drilling February 2017| P5
- 7. February 2017 | P6 Module lifts onto Catcher FPSO completed • Outfitting of FPSO progressing well • 13/13 modules lifted onto FPSO • ~2,000 people working on the vessel • On track for summer 2017 FPSO sailaway
- 8. Catcher schedule 20172016 2H • Plateau rates of 50 kboepd (gross) • $1.6bn total project cost • Potential further savings from contingency release and FX • Forward cost exposure reduced significantly BP3 & BP 5 completed Drilling at Varadero (4 wells) Installation of Buoy and Mooring System Module Lifts Installation of risers Hull mated Onshore pre-comm and comm Drilling at Burgman (2 wells) FPSO transit to Catcher field FPSO buoy and hook-up First oil February 2017 | P7 Drilling at Catcher (4 wells) * Assumes $1.25/£ to end 2017, then $1.3/£ and 20 wells drilled Topsides integration Capex - 29% reduction in costs secured * $mm 0 50 100 150 200 250 300 350 2014 2015 2016 2017 Sanctioned budget Actual/current forecast
- 9. Tolmount – next phase of growth Indicative metrics (gross) • 450 Bcf • Capex <$600m • Opex: c.$7/boe • Peak production : 200 mcfd • First gas 2020 High return project in a low gas price environment Timetable to sanction • Concept select Q1 – Standalone, normally unmanned or subsea tie-back to nearby facilities • Project optimisation – Capex reducing – Potential 3rd party funding • FID targeted for 2017/early 2018 • Partial sales process underway February 2017 | P8
- 10. Southern Gas Basin: portfolio of opportunities Babbage (47% op) • Infill opportunities Ravenspurn Deep (5% carried interest) • BP/Perenco long-reach well planned for late 2016 Newton (50% op) Cobra (50% op) • 250 Bcf gas discovery • Potential tie back to Babbage 30km radii Portfolio of opportunities which are economic at <30p/therm February 2017 | P9 Minerva Tolmount (50% op) • Discovered Oct 2011 • 2 appraisal wells in 2013 • 450 bcf of resource • Largest UK gas discovery since Breagh in 1997 • Significant upside (E.Tolmount, Malin)
- 11. February 2017 | P10 • Licence extended to 2020 • Good progress on FEED in 2016 – Facilities capex and opex cost estimate reductions from FEED contractors’ collaboration – Logistics and drilling cost estimate reductions following extensive market engagement – $45/bbl current estimated breakeven price • Forward focus on commercial and fiscal work streams & securing a financing solution for the development Estimated capex to first oil now $1.5bn Sea Lion Phase 1 – reducing breakeven price
- 12. • Sureste Basin is a prolific hydrocarbon province (62 bn bbls of proven oil) • Exercised option to increase to 25% in Block 7 − Shallow water (<150m) − Same salt flanks and sub- salt plays as the US Gulf of Mexico − Large Zama well to spud early Q2 Mexico – potential for material value creation 2017 - 20182016 2H Delivery of reprocessed 3D seismic across 2 blocks Confirm final drilling candidates Tender for a moored, semi- sub rig for Block 7 First exploration well on Block 7 First exploration well on Block 2 February 2017 | P11 Flat Spot Zama Prospect
- 13. Net debt & refinancing update February 2017 | P12 Debt type Description Facility size Maturity Bank debt RCF & LC US$2.5bn 2019 Bank debt Term Loan US$300m Dec. 2017 US Bonds Private Placement US$380m No maturity before 2018 German Bonds Schuldschein US$130m 2018 & 2020 UK Bonds Convertible US$245m 2018 UK Bonds Retail bond GBP150m 2020 Private lenders Publically traded debt • Long form term sheet agreed and circulate to lenders for formal credit committee approval − Preservation of the full amount of existing facilities including undrawn amounts − Alignment of all maturities to 2021 or later − Amendment of the group’s financial covenants − Provision of a comprehensive security package to lenders − Enhanced economics to lenders − Certain governance controls • Aim to have creditors locked up to the final terms during February • Negotiations with convertible bondholders ongoing Net debt of $2.8bn, marginally down fromQ3 Cash and undrawn facilities of c. $600m
- 14. 2016 2018 Infills Tolmount Sea Lion $2.25bn $1.6bn Sanctioned budget Forecast Maintain competitive cost base Continuing production growth Catcher delivery Select highest return projects for sanction Deliver debt reduction Outlook 1 2 3 4 5 20% >50% 30% 2016 Solan Catcher $15.7/boe 5.2x 3x $12/boe $20/boe February 2017 | P13 2016 2017 2018 IRR Net debt/ EBITDAX
- 15. 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 February 2017