2015 Annual Results 25 February 2016
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 2016 | P1
Introduction Tony Durrant Chief Executive Officer
2015 – delivering on our targets Strong production 57.6 kboepd, above guidance, driven by high operating efficiency and performance despite disposal of non-core assets $16/boe opex, down >$100m from 2014 Reducing costs Gross G&A costs c.$230 million, down >$75 million from 2014 Net debt c.$2.2 billion, modest increase reflecting corporate actions Focus on net debt offsetting ongoing investment in Solan and Catcher Funding flexibility and Renegotiated covenant terms; $1.2 billion liquidity at year end; liquidity unsecured facility with no redeterminations Progressing Solan and Solan: final commissioning; first oil delayed by severe weather Catcher Catcher: first oil on track 2017, key milestones achieved, under budget Sea Lion Phase 1 project scope modified with lower break-even oil Progressing Sea Lion price; draft FDP submitted and FEED contracts in place Reserve and resource 2P reserves increased by 89mmboe to 332mmboe additions Resource additions at Zebedee and Isobel Deep Asset disposals (Norway and Aceh, Indonesia) Refocusing the portfolio Value accretive E.ON asset acquisition agreed February 2016 | P3
Proposed E.ON acquisition – rationale and status • Strengthens Premier’s position in UK North Sea with its associated tax benefits; opportunity to generate operating Proforma 2015 Production and cost synergies • Continues Premier’s track record of capturing long term value through acquisition at low points in the oil price cycle • Adds stable UK gas revenues to the portfolio; rebalancing Total 73 kboepd commodity exposure • Adds high quality assets at a compelling valuation with a valuable hedging position in 2016 and 2017 • Adds immediate cash generative production, tax synergies ProformaYE15 Reserves and material covenant accretion with rapid payback – meeting Premier’s stated acquisition criteria • Status of the acquisition: – Good progress has been made with lending group Total 375 consents mmboe – Shareholder circular expected to be issued in March – Completion expected in Q2 February 2016 | P4
UK Robin Allan North Sea and Exploration Director
Solan – first oil shortly, moving on to second oil First oil • All construction and subsea infrastructure fully commissioned • Tanker trials complete and habitation achieved (25 persons on the platform) • Winter weather has impacted final commissioning – platform access 1/3 rd vs Winter 2014 • <10,000 hours remaining Full production by Q3 Delivering second oil and ramp up to 20-25 kbopd full production • Test the facilities and planned shut down ahead of second oil • Utilise Superior Flotel to maximise workforce on platform to complete remaining systems • Complete W2 and tie in; recommence production and ramp up • Complete P2 z and tie in by mid-year February 2016 | P6
Catcher – under budget and scheduled for 2017 2015 Highlights $1.6bn FPSO: First section delivered in December (gross budget • 2015 subsea installation programme to first oil) successfully completed Under budget at 2015YE • Fabrication of 2016 subsea equipment and mooring system on schedule • Hull fabrication on-going in Japan and Korea Aerial View of Catcher Modules; Singapore – First section delivered in December • Topsides and Turret fabrication underway in ProFab, Dynamac and Asia Offshore yards Drill Centre Manifold Towhead Key milestones for 2016 • 2016 subsea installation programme – Remaining templates, bundles and riser system E-House Completed – Buoy and Mooring system (to be ready for FPSO in 2017) • Commencement of hull and integration work in Singapore from summer 2016 Opex $20/bbl at plateau production c.50 kbopd February 2016 | P7
Catcher – initial drilling results encouraging • Ensco 100 rig on hire since July • 3 wells drilled with excellent operational performance – two injectors (CTI1 and CCI2) Well results confirm – one producer (CCP3) high quality • Pre-drill predictions for reservoir depth, thickness reservoir and extent confirmed • Reservoir quality and flow rates met or exceeded expectations • Injector well tests demonstrated water injection capability into the field • 5 further development wells and an exploration well planned for 2016 Catcher exploration well 29-1 Catcher CCP3 producer well Cromarty reservoir 0 500ft February 2016 | P8
E.ON UK assets – strong start to 2016 Elgin Franklin Area (5.2% non-op.) Tolmount (50%, op.) • Current production > 110 kboepd World class • Resources 200 Bcf – 1Tcf (gross) Significant (gross) asset with • Peak production 150-200 mmcfd gas • Current production rates expected long-term (gross) discovery through to 2019 production • 2017 investment decision, first gas • Development drilling programme 2019/2020 • Low opex of $8/boe in 2016 • Further discoveries and prospects 2016 YTD Production Huntington (38.5%, op.) Babbage (47%, op.) • Existing Premier field, equity • Current gas production interest increases to 100% • Field outperformance • 2016 ytd production: 13 kboepd • Plans to operate unmanned (gross), in line with 2015 Opportunity In-field and to reduce costs near-field and enhance growth production opportunity February 2016 | P9
SE Asia & Falkland Islands Neil Hawkings SE Asia & Falkland Islands Director
South East Asia – reliable low cost production Vietnam • Strong 2015 production and operating efficiency Operating – 32 kboepd (gross) production costs • Progressing further cost reductions c.$13/bbl • Planning f0r future infill programme targeting unswept areas and low risk new reservoirs – To increase production above 2015 levels Indonesia • High operating efficiency and robust demand maintained production levels – Market share exceeded contract Operating – Will increase as other suppliers decline costs • Longer term, Indonesia (Batam) and Singapore c. $8/bbl are both seeking additional volumes • Planning further developments to increase production beyond 2018 – Bison, Iguana, Gajah Puteri – Lama exploitation – Tuna February 2016 | P11
North Falklands Basin – potential confirmed Successful exploration programme now complete • Zebedee discovery proves up additional resource to northern Sea Lion North Falklands Basin development complex – Adds c. 60 mmbls resource to Sea Lion Phase 2 520 mmbls; 2 Phases • Isobel Complex potential confirmed – Potential for >480m oil column – Multiple additional oil-bearing sands • Programme curtailed due to rig performance issues • Further appraisal concurrent with Sea Lion development Isobel Complex de-risked Isobel Deep Geobody N February 2016 | P12
Sea Lion – low cost option for large future value • Phase 1 project economics enhanced “Collaborative partnership” – 220 mmbbl from NE & NW areas of PL032 Subsea FPSO – 18 wells (13 pre-drilled) and 20 year field life Installation – $1.8bn capex to first oil unchanged (costs down 30%) • Conceptual design work completed • Draft FDP submitted to FIG for comment Subsea Risers • Completed SPA amendment with RKH Falling Prod’n System break-even • Phase 1 FEED is progressing cautiously price • Anticipate securing further cost reductions • Looking to bring in additional upstream partner “Collective costs incentives” Final Investment Decision Timing Will remain dependent on: • Achieving attractive rates of return Enhanced • The outlook for long term oil prices project economics • The level of cost reductions secured • Premier’s ability to fund project – without risking the balance sheet February 2016 | P13
Finance Richard Rose Finance Director
Strong cash flows despite lower oil prices Capital expenditure ($m) 12 months 12 months to 31 Dec to 31 Dec 2015 2016E 2015 2014 $m $m Exploration $216 c$100 Development $854 c$600 Working Interest production (kboepd) 57.6 63.6 Total $1,070 c$700 Entitlement production (kboepd) 53.4 57.8 Realised oil price (US$/bbl) - post hedge 79.0 101.0 Comprises proceeds from the sale of Block A Realised gas price (US$/mcf) - post hedge 6.5 8.4 Aceh and Norway and a positive adjustment from Scott area disposal $m $m Cash flow from operations 903 1,133 Liquids hedging (incl E.ON) Taxation (94) (209) 1H 2016 2H 2016 Operating cash flow 809 924 Barrels hedged 1,890 2,530 (Kbbls) Capital expenditure (1,070) (1,514) Average price 74.7 72.4 Disposals 220 131 ($/bbl) Finance and other charges, net (101) (120) Dividends - (44) Share buy back - (93) Net cash in (out) flow (142) (716) Net Debt (2,242) (2,122) February 2016 | P15
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