Investor Presentation November 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. November 2017 P1
Executive Summary
2017 a year of strong delivery Production Cost Base Disposals Catcher YTD Production average ytd 76.6 kboepd YTD Opex of $15.9/boe; FY capex guidance reduced to $300-310m YTD Wytch Farm and Pakistan sales announced; other processes ongoing YTD FPSO arrived in the field - commissioning underway; positive drilling results Full Year Target FY Guidance remains to 75-80 kboepd Full Year Target Deliver FY guidance of opex c$16/boe and capex of $300-310m Full Year Target Completion of Wytch Farm and Pakistan Full Year Target Deliver first oil by year end Tolmount Sea Lion Exploration Net Debt Reduction YTD HoT signed with infrastructure partner; draft FDP submitted to OGA YTD Negotiating funding packages YTD World class oil discovery at Zama-1, Mexico YTD Positive cash flow in H1; ytd in line with forecast Full Year Target Progress for FID in H1 2018 Full Year Target Progress financing and commercial initiatives Full Year Target Define appraisal and development plans for Zama Full Year Target Generate positive net cash flow post disposals and debt reduction November 2017 P3
Production overview Largest 5 fields account for c. 70% of production November 2017 P4
Development portfolio >800 mmboe of discovered but undeveloped reserves and resources November 2017 P5
Delivering on our strategy Acquisitions Opportunistic acquisitions Stakeholder Returns Production Development Exploration 77 kboepd Costs Operated FPSO s Partner-funded Proven basins Under drilled Value $16/bbl Debt Reduction Portfolio Management Disposals realising value November 2017 P6
Future plans Portfolio Management Acquisitions Disposals by majors Tax optimisation Portfolio Management Disposals Non core assets Mitigating risk Stakeholder Returns Production Development Exploration Continuing growth Reserve life >10 yrs Operating Costs $15-$17/bbl Catcher Tolmount Sea Lion Zama Tuna High value, near field Material upside in Mexico and Brazil Value Debt Reduction Balance Sheet Management Free cash flow 2018-2022 reducing debt Net debt : EBITDA <3x November 2017 P7
Producing Portfolio
Chim Sáo, Vietnam (53.125%, operator) 2017 ytd 15.0 kboepd High operating efficiency and strong Strong reservoir performance $9/boe operating cost 1 st infill well completed and tied-in Outlook Further infill well planned before year end Improved Production Profile kboepd (gross) 35 30 25 20 15 10 5 0 Current Previous 2016 2017 2018 2019 2020 55 mmboe at sanction 57 mmboe produced to date 59 mmboe reserves remaining 5IPST1 20P November 2017 P9
Natuna Sea Block A, Indonesia (28.67%, operator) 2017 ytd 12.7 kboepd, above budget Singapore demand above take or pay (49% of GSA vs 47% contractual share) High operating efficiency Opex of c.$8.7/boe Lama development well (WL-5X) tied into production; producing 20-25 mmscf/d Outlook Singapore demand stable GSA1 market share increasing BIGP first gas 2019 93 Bcf $340m gross capex 30% IRR BIGP NSBA Production net to PMO (kboepd) 20 15 10 5 0 Market Share GSA1 (%) 2016 2017 2018 2019 2020 100 80 60 40 20 0 November 2017 P10
Huntington, Central North Sea (100%, operator) 2017 ytd 13.5 kboepd, 23% above budget High FPSO operating efficiency Strong reservoir performance HoT agreed on lease extension and extended Shell term deal Outlook Maximise production Currently producing ~15 kboepd November 2017 P11
Solan, West of Shetlands (100%, operator) 2017 ytd 6.2 kboepd Central reservoir on prognosis; Eastern area of field under-performing Outlook P1 producing steadily on free flow P1 workover deferred Options to improve production being evaluated; potential infill well 2019 Top Solan Sand Depth Map W1 500m P1 W2 P2 November 2017 P12
Elgin-Franklin, Central North Sea (5.2%) 2017 ytd 5.5 kboepd, currently >7 kboepd Low opex of c.$8/boe Outlook Long field life; production forecast to continue until 2037 350 mmboe remaining reserves Ongoing infill drilling, well intervention programme and exploration upside November 2017 P13
Portfolio Potential
Catcher on schedule for start up by year end All 12 wells planned pre-first oil now complete confirming good quality oil Subsea activities complete; short campaign to support hook-up and commissioning operations post arrival of FPSO Arrived in North Sea in October Hook up and Commissioning programme progressing well On schedule for 2017 first oil Important cornerstone of Premier s debt reduction Project capex down 29% on sanction September November 2017 P15
Catcher Commissioning Arrival in the UK and Hook-Up 4-6 Weeks Commissioning 3-4 Weeks Harbour On location Cone Plug Removal Buoy Hook-Up Risers Umbilical's ESDV s * Swivel Stack Reinstatement Pre-Commissioning Commissioning Where possible equipment was leak tested, commissioned and systems accepted by operations in Singapore prior to sail away The voyage and movement of the vessel and equipment requires them to be re-tested ahead of the introduction of hydrocarbons Tanker activities Testing of offloading hose connection Final rotation test Topsides activities: Pipework: Nitrogen/helium testing; and Deluge testing Tubing: Leak testing Electrical & Instrumentation: Pig tail termination & tests; and Removed equipment reinstated and tested Subsea activities Completion of umbilical core flushing Gas export riser dewatering Tree & manifold valve function testing Ready for the introduction of hydrocarbons from Catcher field Teekay shuttle tanker Gas export line commissioned prior to start up November 2017 P16
Daily Oil Potential (stb/d) Catcher Commissioning & Production Profile Fuel Gas Import Gas Export Comm. Catcher First Oil Oil Stabilisation Produced Water Fuel Gas Primary Gas Handling Varadero First Oil Permeat. Comp Flash Gas Comp Gas Lift Burgman First Oil Water Injection 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Catcher Varadero Burgman Catcher is the initial field on production due to it s ability to produce oil in a stable fashion for the first stages of the FPSO plant commissioning Each field will be brought on in the following manner Well clean up (initial clean up restricted by rig surface equipment) Well test through the subsea multi-phase meters Restricted rate to manage gas rates through commissioning period Following gas train commissioning completion and the introduction of Burgman fluids the plant will be run at 60 kbopd November 2017 P17
Catcher continuing positive drilling results 13 wells completed to date 4 on each of Catcher, Varadero and Burgman fields planned pre first oil Phase 2 first well on Catcher Good test results: Net pay encountered by the 8 production wells > 30 % longer than forecast Initial production delivery rate per well >40% higher than predicted on average Improved production profiles anticipated of c.60 kboepd Review of FPSO capacity underway Burgman Varadero Catcher Improved production profile anticipated Plateau production up 20% on sanction November 2017 P18
Tolmount infrastructure partnership Partnership with Dana Petroleum and CATS Management Ltd (1) Dana and CML will jointly own: platform export pipeline Tolmount gas will use the facilities LoF tariff Premier s share of project capex $100m Premier retains 50% equity interest in the licence Excellent project economics IRR >50% at gas price of 30p/therm CML 31% Capex Split Dana 50% PMO 19% Estimated Tolmount Capex (Gross) $m Development Scope Gross Capex (Real, $mm) % pre 1 st gas Platform 90 100% SURF (20 pipeline to beach) 100 100% Host Terminal modifications 150 85% Drilling (2) 140 64% PMT 70 92% Total 550 - November 2017 P19 (1) an Antin Infrastructure Partners portfolio company (2) Based on plan where one well is on-stream pre-1 st gas High return project robust down to low gas prices
Tolmount progressing on schedule for FID in 1H 2018 Initial phase: targeting 540 Bcf resources Peak production capacity 300 MMscfd FEED contracts awarded; engineering underway Tendering of major project scopes underway; pipeline, drilling rig and platform proposals received Draft FDP submitted to OGA Timing: Board approval Q4 &FID 1H 2018 First gas 2020 Dimlington Terminal >1 bcf gas processing capacity, 600 mmscfd installed compression capacity plus additional condensate processing Perenco Dimlington SNSPS (Cleeton / Ravenspurn) West Sole (connected to Perenco Easington) Tolmount Gassco Langeled Ormen Lange Tolmount Centrica Easington Rough & York Subsurface Depletion Plan 4 initial development wells in Tolmount Future phases TE, TFE & Mongour Offshore Facilities NUI platform with 6 slots / 4 wells Offshore PWT treatment Riser / J-tube pre-investment for area development 20 x 48kn Gas Export pipeline 3 MeOH (and CI) import pipeline Host Terminal Dimlington host New reception & condensate processing Shared gas processing & compression November 2017 P20
Tolmount future phases planned Tolmount East Subsea tie-back or small platform 2019 well planned to confirm resource Tolmount Far East Subsea tie-back or small platform to Tolmount or Tolmount East Mongour Subsea tie-back or extended reach well from Tolmount East Tolmount area ~ 1 Tcf Mongour Tolmount East Tolmount Far East 3rd party business potential A new hub with 20+ year life Tolmount Indicative production profile SW 42/28d-12 NE Tolmount Far-East Gas water contact Tolmount Tolmount East November 2017 P21
Zama-1 oil discovery - volume estimates W Full stack reprocessed seismic data in depth Zama-1 Well Flat Spot E Major hydrocarbon discovery in shallow water, offshore Mexico Initial gross oil in place estimates are 1.2 1.8 Bnbbls (unrisked P90-P10 resources of 400-800 mmboe), exceeding pre-drill estimates Contiguous gross oil bearing interval of over 335m, with over 200m of net oil bearing reservoir Light oil : 28-30 API ENSCO 8503 Gross oil bearing interval to scale Good conformance of seismic amplitude with structural contours November 2017 P22
Zama illustrative development scenario Location of Zama discovery Amoca Zama Hokchi Indicative development metrics Resources 400-800 mmboe 1 Daily peak production 100-150 kbopd Capex +/- $1.8 billion Appraisal 2018-19 First oil 2022-23 (1) Including the extension onto the neighbouring block Potential to leverage Mexican fabrication capability Block 7 prospect map Zama November 2017 P23
Annual average oil rate (mbopd) Sea Lion, Falkland Islands (60%, operator) 2017 ytd FEED substantially completed Breakeven reduced to c$45/bbl Capex to first oil reduced to $1.5bn Field opex reduced to $15/bbl Indicative FPSO cost of $10/bbl (LoF) Outlook Positive commercial and fiscal engagement with FIG Positive engagement with contractor market and export credit government funding sources Licence extension to May 2020 160 140 120 100 80 60 40 20 0 Phase 2 Phase 1 0 5 10 15 20 Years from first production November 2017 P24
Tuna, Indonesia (65%, operator) Highlights Discovered in 2014 by the Singa Laut-1 and Kuda Laut-1 wells >90 mmboe Evaluation of potential development scenarios ongoing Government agreement signed with Vietnam and Indonesian governments re: connection to existing infrastructure in Vietnam Granted 3 year extension to exploration period of licence November 2017 P25
Ceara Basin, Brazil exploration Largest acreage holder in the Ceara basin 4,000 km 2 of fast-track seismic data across all 3 blocks received in 2016 Final depth migrated broadband seismic data received in April 2017 Well locations to be selected during 2017 Licence extensions received for all 3 blocks Drilling operations planned for 2019 CE-M-717 SW 1-CES-112 1-CES-158 NE Berimbau Up-dip pinch out and fault offset Berimbau CE-M-661 CE-M-665 Pecem K50 discovery Maraca K40 8km Ganza K40 Pecem K40 Data Proprietary to PGS Investigacoa Petrolifera Limitada Excellent imaging on new broadband seismic of Upper Cretaceous turbidite channel sands CE-M-717 November 2017 P26
Financials
Net debt and hedging Net debt Net debt of $2.8bn Cash flow positive for FY including planned disposals; debt reduction accelerating once Catcher on-stream Average cost of debt c7% going forward Targeting Net Debt/EBITDAX <3x by end 2018 Liquids and UK gas hedging as at 31 October Oil hedges % Hedged Fixed price oil hedges Q4 2017 H1 2018 H2 2018 Price ($/bbl) % Hedged Price ($/bbl) % Hedged Price ($/bbl) 19% 52.4 30% 53.5 16% 55.7 Oil option sales 22% 51.1 20% 54.7 - - UK gas hedges % Hedged Price (p/therm) % Hedged Price (p/therm) % Hedged Price (p/therm) Fixed price 40% 49.2 34% 48.4 13% 43.2 Comprehensive refinancing completed Facilities confirmed 1 2,000 1,000 0 $3.4 bn Drawn Debt Maturities extended 1 4,000 Previous Revised 3,000 $4.0 bn Cash & Undrawn Total Facilities (incl cash) 2017 2018 2019 2020 2021 2022 1 FX as at when facilities entered into Other key amended terms Covenant profile re-set with headroom Enhanced economics (~1.5%) to lenders A warrant package to lenders Convertible bond re-priced Corporate governance controls November 2017 P28
Financial outlook Operating Costs 2014-2017 Down from c$20/boe to c$16/boe Over $300m of absolute cost savings delivered since 1/1/2015 2018-2020 Stable operating cost base at current levels $15-17/boe Capex 2014-2017 Reduced from over $1.0bn pa. to $300-310m in 2017 Reduced forward commitments 2018-2020 Maintain at current run rate depending on new projects Disciplined approach to capital allocation Portfolio management 2014-2017 Over $350m realised from disposals Significant value created through E.ON acquisition 2018-2020 Further disposals to accelerate deleveraging Net debt 2014-2017 Increased due to investment and weakness in oil price Reducing by end 2017 2018-2020 Leverage ratio below 3.0x and falling Priority remains reduction in absolute levels of net debt November 2017 P29
November 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