Investor Presentation. May 2016

Transcription

1 Investor Presentation May 2016

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. May 2016 P1

3 Executive Summary

4 2016 progress against targets Maximise production Further cost reductions Solan on plateau (20-25 kboepd) Progress Catcher Refocusing the portfolio Focus on net debt Manage covenant headroom On track to deliver at or above upper end of FY guidance of kboepd 88% operating efficiency in Q1 Opex tracking 10-20% below budget; expected FY opex of c. $17/boe Gross G&A on track to deliver 10% reduction on 2015 (ex E.ON) Solan on-stream 12 April, >14 kboepd tested from P1 P2 expected on-stream by mid-year Pre-first oil capex 15% lower at $1.35 bn; first oil on schedule for 2017 FPSO delivery to Singapore by July; targeting subsea work completion by Q4 Acquisition of E.ON s UK North Sea assets completed On-going asset disposals Net debt of $2.68 bn at end April; 2016 capex spend front-end loaded Expect to be cash flow positive at oil prices above c. $50/boe in Q4 Discussions ongoing with lenders to secure financial covenant waiver if required May 2016 P3

5 Looking forward Strategy Focus on Advantaged Assets UK, SE Asia, Falklands Disposal of non-core assets Appropriate balance of current cash flow, development projects and longer-term upside Financial Position Accelerate Debt Reduction Take necessary corporate actions to minimise net investment in 2016 (as in 2015) 2017 will see de-leveraging at the current forward curve Continue Focus on Cost Base Further opex and G&A savings in 2016 Current and future capex spend reductions Opex ($mm) FY 2014 (actual) G&A ($mm) Budget Solan, Huntington FY 2015 (actual) 2016 Budget 100 FY 2014 (actual) 2015 Budget FY 2015 (actual) 2016 Budget May 2016 P4

6 Looking forward Portfolio Management Proven Track Record in Acquisitions/Divestment 6 separate transactions since 2013, focused on pre-development assets E.ON portfolio added 70 mmboe at cost of <$2/bbl; offers further opportunities for asset disposal $mm Divestments 120 Acquisitions May 2016 P5 Forward Position Quality 2019 Portfolio kboepd; $15/bbl opex; long life assets Balance sheet debt reducing rapidly Highly leveraged to oil price recovery Low cash cost base; low effective tax rate Costs re-set to a sub-$50 world c. 850 mmboe of reserves and resources Illustrative Base Case $mm $60/bbl $50/bbl $40/bbl Operating Cash flow $70/bbl $55/bbl $45/bbl $80/bbl $70/bbl $60/bbl Capex & Abex Operating Cash flow Capex & Abex Operating Cash flow Capex & Abex

7 Asset update

8 Summary of asset upsides UK Premier Upside in Huntington and Solan Elgin-Franklin producing above budget Opex and capex savings in Catcher project Potential reserve upgrade at Catcher Targeting substantial cost reductions Potential disposal strategies Q production 18 kboepd Q opex $30/bbl EXPLORATION Plan for 2018 drilling programmes Mature Mexico and Brazil (Ceara Basin) drilling targets May 2016 P7 PAKISTAN Ongoing infill drilling Sale process underway 2016 Q1 production 8 kboepd 2016 Q1 opex $3/bbl FALKLAND ISLANDS Targeting savings to reach 20% IRR at $55/bbl Seeking long term partner(s) Mature phase 2 and 3 concepts Sea Lion: current economics 20% IRR at $65/bbl VIETNAM Infill programme targeting 18 kboepd (2018) Seeking further cost reductions FPSO lease restructuring Q production 17 kboepd Q opex $7/bbl INDONESIA Ongoing developments (BIGP, Tuna, Lama) Seeking further cost reductions Increasing market share over time ( 60%) Synergies with Block B Q production 14 kboepd Q opex $9/bbl GSA1 market share 44%

9 Current production high operating efficiency North Sea (17.6 kboepd) 99% OE and lower decline from Huntington Unplanned shutdown on B Block Solan on-stream April E.ON production consolidated from 28 April Production (kboepd) OE 83% OE 70% 2015 Q Vietnam (17.4 kboepd) Delivering ahead of expectations High operating efficiency Better than predicted reservoir performance Production (kboepd) OE 87% OE 96% 2015 Q Pakistan (8.3 kboepd) Well-established gas producing fields Generates positive, stable cash flows Formal sales process ongoing Production (kboepd) OE 95% OE 95% 2015 Q Group Maintained high operating efficiency E.ON delivered 17 kboepd in Q1 New production from Solan Expect to be at /above kboepd OE 90% FY GUIDANCE Solan + E.ON OE 88% 2015 Q Indonesia (14.0 kboepd) Singapore demand above take or pay GSA1 share 44%; above contractual share of 40.9% Production (kboepd) OE 93% OE 90% 2015 Q May 2016 P8

10 UK production growth Averaged 17.6 kboepd in Q Group production growth driven by UK: E.ON assets, new Solan production and Catcher Continue to target substantial cost savings; opportunity to generate operating and cost synergies UK long life assets include Elgin-Franklin, Wytch Farm & Catcher $3.5 bn of UK tax losses and allowances and c. $550 m of Investment Allowances Solan Kyle Balmoral Area Huntington Solan kboepd E.ON kboepd Catcher kboepd Babbage Wytch Farm Elgin Franklin Group Base Production May 2016 P9

11 South East Asia reliable low cost production Vietnam Strong Q production and operating efficiency 32.8 kboepd (gross) production 96% operating efficiency Progressing further cost reductions Planning f0r future infill programme targeting unswept areas and low risk new reservoirs 2015 operating costs c.$13/bbl Indonesia High operating efficiency and robust demand maintained production levels Market share exceeded contract Will increase as other suppliers decline Longer term, Indonesia (Batam) and Singapore are both seeking additional volumes Planning further developments to increase production beyond 2018 Bison, Iguana, Gajah Puteri Lama exploitation Tuna 2015 operating costs c. $8/bbl May 2016 P10

12 Solan first oil achieved, moving on to second oil P1 on-stream 12 April rates of 8 kbopd achieved from natural flow, rising to 14 kbopd with ESP Planned shut down ahead of second oil W2 tied in Final commissioning of water injection plant underway ESP completion for P2 being installed with tie-in planned for early June Utilise Superior Flotel to maximise workforce on platform to complete remaining systems Re-start production and ramp up to plateau rates of kbopd Plateau production by Q3 of kbopd May 2016 P11

13 Catcher under budget and scheduled for 2017 Subsea 2015 subsea installation programme completed; 2016 programme underway Remaining templates installed Installation of bundles and riser system in progress Buoy and Mooring system to be installed over the summer 15% lower pre-first oil capex at $1.35 bn Catcher towhead, Wick Underside of STB Buoy STB Buoy Launching Catcher trailing towhead May 2016 P12

14 Catcher under budget and scheduled for 2017 FPSO Hull fabrication accelerating in Japan and Korea Topsides and Turret fabrication advanced in ProFab, Dynamac and Asia Offshore yards Commencement of hull and integration work in Singapore from Summer 2016 Aerial View of Catcher Modules; Singapore Stern Terra Block; Japan Fore Terra Block, Korea May 2016 P13

15 Catcher initial drilling results encouraging Ensco 100 rig on hire since July wells drilled with excellent operational performance two injectors (CTI1 and CCI2) Two producers (CCP3 and CTP1) Pre-drill predictions for reservoir depth, thickness and extent confirmed Reservoir quality and flow rates met or exceeded expectations Injector well tests demonstrated water injection capability into the field 4 further development wells planned for 2016 Well results confirm high quality reservoir Catcher exploration well 29-1 Cromarty reservoir Catcher CCP3 producer well 0 500ft May 2016 P14

16 Sea Lion complex low cost option for large future value Phase 1 project economics enhanced 220 mmbbls from NE & NW areas of PL wells (13 pre-drilled) and 20 year field life $1.8 bn capex to first oil unchanged (costs down 30%) Conceptual design work completed Draft FDP submitted to FIG for comment Completed SPA amendment with RKH Phase 1 FEED is progressing cautiously Anticipate securing further cost reductions Looking to bring in additional upstream partner Falling break-even price Collaborative partnership Subsea Installation Subsea Prod n System FPSO Risers Collective costs incentives Enhanced project economics Final Investment Decision Timing Will remain dependent on: Achieving attractive rates of return The outlook for long term oil prices The level of cost reductions secured Premier s ability to fund project without risking the balance sheet May 2016 P15

17 North Falklands Basin potential confirmed Successful exploration programme now complete Zebedee discovery proves up additional resource to northern North Falklands Basin development Adds c. 60 mmbls resource to Sea Lion Phase 2 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 Sea Lion complex 520 mmbls; 2 phases Isobel Complex de-risked Isobel Deep Geobody N May 2016 P16

18 Finance

19 Strong cash flows despite lower oil prices 12 months to 31 Dec 2015 $m 12 months to 31 Dec 2014 $m Working Interest production (kboepd) Entitlement production (kboepd) Realised oil price (US$/bbl) - post hedge Realised gas price (US$/mcf) - post hedge $m $m Cash flow from operations 903 1,133 Taxation (94) (209) Operating cash flow Capital expenditure (1,070) (1,514) Disposals Finance and other charges, net (101) (120) Dividends - (44) Share buy back - (93) Net cash in (out) flow (142) (716) Net Debt (2,242) (2,122) Capital expenditure ($m) Comprises proceeds from the sale of Block A Aceh and Norway and a positive adjustment from Scott area disposal Liquids hedging (incl E.ON) Barrels hedged (mmbbls) Average price ($/bbl) E Exploration $216 c$100 Development $854 c$630 Total $1,070 c$ May 2016 P18

20 Income statement 12 months to 31 Dec 2015 $m 12 months to 31 Dec 2014 $m Sales and other operating revenues 1,099 1,629 Cost of Sales (661) (987) Impairments (1,024) (784) Gross profit/(loss) (586) (142) Exploration/New Business (109) (84) General and administration costs (14) (25) Disposals 1 3 Operating profit/(loss) (708) (248) Financial items (122) (136) Profit/(loss) before taxation (830) (384) Tax credit/(charge) (241) 174 Profit/(loss) after taxation (1,071) (210) Operating costs ($/boe) UK $37.2 $30.0 $27 Indonesia $10.0 $10.0 $11 Pakistan $3.3 $3.7 $5 Vietnam $14.6 $11.7 $13 Group $18.5 $15.5 c$16-17 Exploration write offs include Badada well in Kenya and uncommercial Bonneville discovery in UK $3.5 bn of UK tax losses and allowances EBITDAX 752 1,074 May 2016 P19

21 Cost reduction continuing Initial Cost Reductions 2014/15 Further Actions Contractor rate cuts Contract renegotiations G&A headcount reductions of c20% Discretionary capex/opex cuts Operating efficiencies Lower cyclical costs (fuel/insurance etc.) Further contractor rate cuts Additional contract renegotiations FPSOs Logistics Collaboration with other operators Phasing of capex payments with suppliers 2015 Opex down 25% G&A down 25% 2016 Opex down 10-20% G&A down 10% Opex ($mm) FY 2014 (actual) G&A ($mm) FY 2014 (actual) 2015 Budget 2015 Budget Solan, Huntington FY 2015 (actual) FY 2015 (actual) Committed capex profile ($mm) 2016 Budget 2016 Budget P&D Capex Exploration F 2017F 2018F More than 250 further initiatives identified targeting savings of > $50m p.a May 2016 P20

22 Covenant compliance and mitigating actions Covenant position amended Net debt $2.2 billion (YE 2015) Headroom > $900m (YE 2015) Strong support from banks & bondholders Key focus on compliance in low oil price environment Tested half yearly at 30 June and 31 Dec Likely to require relaxation of covenants if low oil price persists Financing structure Liquidity Cost of debt Corporate unsecured No reserve base determinations No amortisations $1.2 bn cash & undrawn facilities at year end 2015 No maturities until end % fixed interest rate Average debt costs of 3.5% in Mitigating actions Capex phasing, pre-paid oil sales, further cost reductions, sale and leaseback, asset disposals E.ON UK asset acquisition materially covenant accretive Drawn debt maturities (US$mm) May 2016 P21

23 End P reserves and resources Falklands Indonesia Mauritania Pakistan UK Vietnam Total On Production P Approved for Development Justified for Development Total Reserves C Development Pending Development Unclarified / on hold Development not viable Total Contingent Resources Total Reserves + Contingent Resources May 2016 P22

24 Appendix

25 Rationale for the E.ON acquisition Strengthens Premier s position in UK North Sea with its associated tax benefits; opportunity to generate operating and cost synergies Continues Premier s track record of capturing long term value through acquisition at low points in the oil price cycle Proforma 2015 Production Elgin-Franklin area Huntington Adds stable UK gas revenues to the portfolio; rebalancing commodity exposure Adds high quality assets at a compelling valuation with a valuable hedging position in 2016 and 2017 Total 73 kboepd Other CNS Babbage area Other SNS Premier Assets acquired at $1.6/boe based on CPR estimate of 2P reserves vs. UK North Sea average of $13/boe (since 2000) ProformaYE15 Reserves CPR values the net asset value of 2P reserves and SNS infrastructure at $494 million (pre-tax) vs. purchase consideration of $120m Adds immediate cash generative production, tax synergies and material covenant accretion with rapid payback meeting Premier s stated acquisition criteria Total 402 mmboe Elgin-Franklin area Huntington Other CNS Tolmount Babbage area Premier May 2016 P24

26 E.ON UK assets strong start to 2016 Elgin Franklin Area (5.2% non-op.) 34.6 mmboe net reserves ytd production: 5.3 kboepd (net), 14% up on 2015 Current production rates expected for next 3 years Development drilling through to 2019, 7 new wells, capex (net) 50m Low opex of $8/boe in 2016 World class asset with long-term production 2016 YTD Production Significant gas discovery Tolmount (50%, op.) c.30 mmboe (169 Bscf) net reserves 1 Est. resources 200 Bcf 1Tcf (gross) Est. peak production mmcfd (gross) 2017 investment decision, first gas 2019/2020 Further discoveries and prospects 1. as per effective date Total 17.2 kboepd Huntington (38.5%, op.) Existing Premier field, equity interest increases to 100% 2.5mmboe net reserves ytd production: 5.2 kboepd (net), in line with 2015 Opportunity to reduce costs and enhance production Elgin-Franklin area Huntington Other CNS Babbage area Other SNS In-field and near-field growth opportunity Babbage (47%, op.) Adds gas production to Premier 19 Bscf (3.2mmboe) net reserves ytd production: 3.4 kboepd (net) in line with 2015 Plans to operate unmanned May 2016 P25 1. as per effective date

27 Financial benefits of the E.ON acquisition Strong cash flow Valuable hedging portfolio Adds significant cash flow in 2016 and 2017 even at current oil/gas prices c.15mboepd of net production and associated cash flow added on completion YTD production ahead of forecast Acquired with a valuable hedging portfolio in 2016 and : 32% estimated gas 63p/therm, 33% estimated liquids $97/bbl 2017: 21% estimated gas 57p/therm Covenant accretive Significant benefit to covenants (Net Debt to EBITDAX) at 30 June 2016 and 31 Dec 2016 Quick pay back Expected payback of around 2 years, sooner if potential disposal of assets Abandonment liabilities mitigated Sharing of liabilites with seller on Ravenspurn North & Johnston c. 250m of historic tax paid off-settable against future decommissioning expenditure May 2016 P26

28 May 2016 Premier Oil Plc 23 Lower Belgrave Street London SW1W 0NR Tel: +44 (0) Fax: +44 (0)