Annual Results Presentation 01 October 2018 Highlights 2018 - PowerPoint PPT Presentation

2018 Annual Results Presentation 01 October 2018

Highlights 2018 Highlights Group production Catcher plateau production DELIVER kboepd Kboepd (gross) 100 75  Record Group production, high uptime  Catcher – successful execution 75 50  Net debt reduced, profitability restored 50 25 25 EXPLOIT 0 0 2016 2017 2018 2018 Sanction Actual  Field life extensions 1H 2H UK production Operating cash flow  Near field additions kboepd $m  Optimal use of new technology 75 800 600 50 GROW 400 25  Tolmount Main sanctioned 200  Zama appraisal commenced 0 0  Successful capture of new licences 2016 2017 2018 2021F 2016 2017 2018 March 2019 P1

Finance Financial highlights Increased operating Capital discipline Return to profit cash flow maintained Net profit ($m) Operating cash flow ($m) Total capital expenditure ($m) 200 800 800 100 600 600 0 400 400 -100 200 200 -200 -300 0 0 2016 2017 2018 2016 2017 2018 2016 2017 2018 Low and stable Increased free Strengthening cost base cash flow balance sheet Operating cost (incl. leases) ($/boe) Free cash flow ($m) Covenant leverage ratio (Net debt/EBTIDA) 20 400 8 15 6 10 -100 4 5 2 0 -600 0 2016 2017 2018 2016 2017 2018 2016 2017 2018 March 2019 P2

Finance 2018 Financials Catcher increased oil rates delivered a step up in operating cash flow and profits in the second half of 2018 Realised pricing FY 2018 FY 2017 2018 2017 Production (kboepd) 80.5 75.0 Oil (pre hedge) ($/bbl) 67.9 52.9 P&L ($m) Oil (post hedge) ($/bbl) 63.5 52.1 Sales revenue 1,438 1,102 UK gas (p/therm) 57 47 Operating costs (497) (448) Indonesia gas ($/mmscf) 11.2 8.4 EBITDA 882 590 Profit/(loss) before tax 184 (348) Net cash flow $m Net profit/(loss) 133 (254) 400 Cash flow ($m) 300 Operating cash flow 777 475 200 100 Interest and fees (229) (310) 0 Capex (inc. decom pre-funding) (370) (318) -100 2018 1H 2018 2H Disposals 73 202 Net cash flow 251 71 Balance sheet Accounting net debt ($m) 2,331 2,724 Covenant leverage ratio 3.1x 6.0x March 2019 P3

Finance Disciplined spend Capital expenditure Capex $m  Tolmount capex minimised through Abex P&D E&A 400 partnership with Kellas Midstream 46  Development capex lower year-on-year 300 100 38 with completion of Catcher 200  E&A spend heavily weighted towards 234 190 appraisal (Zama, Tolmount East) 237 100  Significant abandonment costs continue to 73 50 be deferred 26 0 2017 2018 2019F Operating and lease costs Operating and lease costs $/boe  Strong cost control across the Group Lease costs Opex 14  Slightly higher per boe metrics due to 12 portfolio effects and disposals 10  Lease costs relate to Catcher, Huntington 8 and Chim Sáo FPSOs 6 4 30% 2 Higher cash margins in 0 2019 2017 2018 2019F March 2019 P4

Finance Net debt reduction continuing Targeting leverage ratio of 1.5x over the cycle Accounting net debt  Significant debt reduction in 2018 $m  Further debt reduction this year 2800 driven by improved cash margins and cost control 2600  Leverage to commodity prices after hedging 2400 – $5/bbl move in price results in c. $60m move in free cash flow  Material liquidity of >$400m 2200 retained  Protection against adverse 2000 interest rate movements through $1bn US LIBOR options 1800 At oil prices above 1600 $45/bbl YE2017 Bond 2018 FCF JV Cash* YE2018 YE2019 generate positive free cash flow Conv. * includes FX movement March 2019 P5

Finance 2019 Finance priorities DELIVER  Continued debt reduction  Maintain low cost base  Fund selected projects without compromising balance sheet  Protect downside through hedging  Refinance by 2021 at lower cost Estimated leverage ratios using accounting net debt as at year-end 2018 1 Oil hedging  40% of 2019 oil production hedged at 6x an average price of $69/bbl 5x UK gas hedging  25% of 2019 UK gas production 4x hedged at an average price of 61p/therm 3x HSFO hedging 2x  25% of 2019 Indonesian gas production hedged at an equivalent average price 1x of c.$11/mmscf -  35% of 2020 Indonesian gas production YE17 YE18 hedged at an equivalent price of Premier European peers US Peers c.$10/mmscf 1 Company, Bloomberg estimates March 2019 P6

Production Group production – two core areas 2018 record of 80.5 kboepd Improved cash margins $/boe (Operating cash flow/production)  New Catcher production 30%  High operating efficiency Higher UK margins 2019 guidance of 75 kboepd  Underlying 5% increase after SE 2018 2019 adjustment for disposals Asia Operating efficiency  Improved cash margins % 96  Strong start to the year, 87 84 averaging 89 kboepd ytd Group production profile (2018 to 2019 ytd) 2018 1H 2018 2H 2019 YTD kboepd 100,000 2018 80.5 kboepd 75,000 2019 75.0 kboepd 50,000 Jan 2018 Jan 2019 March 2019 P7

Production UK production Premier Oil UK UKCS 1 Growing production Extending Basin life kboepd mboepd 15 47 >60 1.4 1.6 1.7 2013 2018 2021F 2013 2017 2021F Reduced operating costs Reduced operating costs US$/boe US$/boe 40 13 13 26 15 2013 2018 2019F 2013 2017 58 kboepd Improved operating efficiency Improved operating efficiency (net) 2019 ytd % % >90 kboepd 64 74 64 79 64 79 95 (gross, operated) 2021 2013 2017 2013 2018 2013 2018 2019 ytd 1 Company, Oil & Gas UK estimates March 2019 P8

Production South East Asia production 2018 net cash flow c.$230 million Stable production High operating efficiency Low cost base kboepd % US$/bbl 30 100 12 20 8 50 10 4 28 28 80 96 10 6 0 0 0 2013 2018 2013 2018 2013 2018 March 2019 P9

Production Chim Sáo (53.125% operated interest) Discovered Chim Sáo in 2006; acquired additional 25% stake for $72 million in 2009 DELIVER  15.2 kboepd (net), uptime>90% Chim Sáo field  Low cost base ($5/boe opex, $6/boe lease) Chim Sáo South Central  $3/bbl premium to Brent; $4/bbl 2019 ytd  Two years of production without a LTI EXPLOIT Chim Sáo South Central  Infill drilling  Well intervention At sanction Produced to date Remaining  Near field addition (Chim Sáo South Central) 55 mmboe 77 mmboe 45 mmboe Chim Sáo production kboepd (gross) 35 At sanction Actual / Forecast Reserves upgraded 30 25 20 Continued field life 15 10 5 0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 March 2019 P10

Production Natuna Sea Block A (28.67% operated interest) Dominant position in the Natuna Sea delivering gas in Singapore under long term gas sales agreements DELIVER Anoa Field and Infill Opportunities  13.2 kboepd (net); increased share of GSA1  High quality offtake contracts  Low operating cost of US$7/boe Gajah Baru On production EXPLOIT Under development Potential  BIG-P first gas  Infill drilling, well workovers  Perforation of bypassed reservoirs Pelikan Laba Laba  PSDM seismic reprocessing Natuna Sea Block A GSA1 market share Naga Gajah Puteri % 60 Bison 50 Benkantan Iguana 40 10 km 30 Natuna Sea Block A 20 10 YE2018 net 2P reserves 2018 GSA1 market share 32 mmboe 52% 0 2013 2014 2015 2016 2017 2018 March 2019 P11

Production Catcher (50% operated interest) Discovered in 2010, increased stake via EnCore acquisition in 2012 Catcher Area oil production profile (gross) DELIVER kbopd 70  Final acceptance certificate issued Sanction Current / Forecast Upside  Increased oil rates of 66 kbopd (gross) 60  High operating efficiency 50 40 EXPLOIT 30  Multiple infill drilling targets  Upside in recovery 20  Optimising performance with technology 10  4D seismic planned for 2020 1H  Catcher North, Laverda sanction 2019 1H 0 Yr 1 Yr 5 Yr 10 Catcher oil rate (2018 to 2019 ytd) kbopd (gross) Final acceptance Catcher Varadero Burgman certificate issued 75 Since Nov 2018 OE since Nov 2018 50 >68 kboepd >95% 25 0 March 2019 P12

Production Huntington (100% operated interest) Acquired through Oilexco (2009), subsequently increased stake via partner defaults (2015) and E.ON acquisition (2016) DELIVER  5.8 kboepd (2018); >6 kboepd 2019 ytd  Reduced lease cost  COP deferred EXPLOIT  Plant modifications to enable gas import  Conversion of former producer to injector Voyageur Spirit Huntington production kboepd At Sanction Actual / Forecast 14 12 10 8 6 4 2 0 2016 2017 2018 2019 March 2019 P13

Production Elgin Franklin (5.2% non-operated interest) Acquired as part of the $120 million E.ON acquisition in 2016 DELIVER  6.7 kboepd (net), high operating efficiency  Low operating cost ($6/boe in 2018)  Reserves increased (extended COP , 4 infills and alignment with operator) EXPLOIT  Infill drilling  Well remedial work  Exploration upside Elgin Franklin production profile kboepd (gross) 140 At acquisition Actual / Forecast 120 100 80 Continued field life 60 40 20 0 2020 2025 2030 March 2019 P14