Investor Presentation January 2017
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. January 2017 | P1
2016 highlights 91% >90% 1 High operating efficiency 2016 2017E >80 kboepd 2 71.kboepd 58 kboepd Step change in production 2015 2016 2016 Q4 3 17 kboepd 15 kboepd Continued portfolio upgrading E.ON acquisition case 2016 2H 4 $18.5/boe $15.7/boe Cost reductions delivered 2014 opex 2016 opex $4 bn 5 $3.4 bn Undrawn Refinancing in progress Drawn Debt Total Facilities (incl LCs) January 2017 | P2
Asia – providing cash flow for the business 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 Low cost, – Tuna, 3rd party business high return opportunities to maintain / grow Vietnam production • >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 January 2017 | P3
UK North Sea – growth story UK overview Solan (100% op) Huntington (100% op) • Improved uptime • Strong reservoir performance • Production currently restricted at • UK drives production growth: • 2016 production significantly 10-13 kbopd • Cost reductions continue to be above budget UK production secured Catcher (50% op) • On track for first oil 2017 • 29% cost reduction secured 2015A 2016A 2017E 2018E • Strong operating base Elgin-Franklin (5.2%) • Tax advantaged position • Long life field • Rates of >130 kboepd (gross) • On-going infill drilling and well intervention programme Wytch Farm (30.1%) • Long life field Tolmount (50% op) • Low cost, high return project • Infill opportunities • Significant area upside • Tolmount East +250 bcf • Tolmount Far East +150 bcf Babbage (47%) • High uptime • Moving to unmanned • Cobra potential tie-back January 2017 | P4
Catcher – ahead of plan Drilling Subsea Burgman BP3 producer well Tay reservoir • 8 wells drilled with excellent operational • Templates, flowline bundles, midwater performance arches and gas export pipeline installed • Pre-drill predictions for reservoir • Buoy and moorings system installed quality and flow rates at • Hook up of risers & umbilicals completed or above prognosis • Installation complete • Drilling programme by Q4 2016 below budget • Subsea programme below budget January 2017| P5
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 January 2017 | P6
Catcher schedule • Plateau rates of 50 kboepd (gross) Capex - 29% reduction in costs secured * 350 Sanctioned budget • $1.6bn total project cost Actual/current forecast 300 250 • Potential further savings from contingency $mm 200 150 release and FX 100 50 0 2014 2015 2016 2017 Hull mated Module Lifts Topsides integration FPSO Onshore FPSO buoy transit to pre-comm and Catcher and comm hook-up field 2016 2H 2017 Drilling at Drilling at First oil Catcher Burgman (4 wells ) (2 wells ) Installation BP3 & BP 5 Installation Drilling at of Buoy completed of risers Varadero and Mooring (4 wells) System * Assumes $1.25/£ to end 2017, then $1.3/£ and 20 wells drilled January 2017 | P7
Tolmount – next phase of growth Indicative metrics (gross) Timetable to sanction • 450 Bcf • Concept select Q1 • Capex <$600m – Standalone, normally • Opex: c.$7/boe unmanned or subsea • Peak production : 200 mcfd tie-back to nearby • First gas 2020 facilities • Project optimisation – Capex reducing – Potential 3rd party funding • FID targeted for 2017/early 2018 High return project in a low gas price environment January 2017 | P8
Southern Gas Basin: portfolio of opportunities Tolmount (50% op) Ravenspurn Deep (5% carried interest) • Discovered Oct 2011 • BP/Perenco long-reach well planned • 2 appraisal wells in 2013 for late 2016 • 450 bcf of resource • Largest UK gas discovery since Breagh in 1997 • Significant upside (E.Tolmount, Malin) Babbage (47% op) • Infill opportunities Minerva Newton (50% op) 30km radii Cobra (50% op) • 250 Bcf gas discovery • Potential tie back to Babbage Portfolio of opportunities which are economic at <30p/therm January 2017 | P9
Sea Lion Phase 1 – reducing breakeven price • 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 January 2017 | P10
Mexico – potential for material value creation • Sureste Basin is a prolific hydrocarbon province (62 bn bbls of proven oil) Zama Prospect • Exercised option to increase to 25% in Block 7 − Shallow water (<150m) − Same salt flanks and sub- salt plays as the US Gulf of Flat Spot Mexico − Large Zama well to spud early Q2 Delivery of Tender for a First First Confirm final reprocessed 3D moored, semi- exploration exploration drilling seismic across 2 sub rig for well on well on candidates blocks Block 7 Block 7 Block 2 2016 2H 2017 - 2018 January 2017 | P11
Net debt & refinancing update • All substantial commercial terms agreed − 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 • Long form term sheet to be circulated to lenders shortly • Aim to have creditors locked up to the final terms during February • Negotiations with convertible bondholders ongoing Debt type Description Facility size Maturity Net debt of Bank debt RCF & LC US$2.5bn 2019 $2.8bn, marginally Bank debt Term Loan US$300m Dec. 2017 Private down from Q3 lenders US Bonds Private Placement US$380m No maturity before 2018 Cash and undrawn German Bonds Schuldschein US$130m 2018 & 2020 facilities of UK Bonds Convertible US$245m 2018 Publically c. $600m traded debt UK Bonds Retail bond GBP150m 2020 January 2017 | P12
Outlook 1 Continuing production growth 2016 2017 2018 $2.25bn 2 $1.6bn Catcher delivery Sanctioned budget Forecast 3 >50% IRR Select highest return projects 30% 20% for sanction Infills Tolmount Sea Lion $20/boe 4 $15.7/boe $12/boe Maintain competitive cost base 2016 Solan Catcher 5.2x 5 Net debt/ EBITDAX Deliver debt reduction 3x 2016 2018 January 2017 | P13
January 2017 www.premier-oil.com 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
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