Investor Presentation May 2018
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 2018 P1
2018 year to date highlights and outlook Production Cost Base Disposals Catcher 2018 YTD Q1 production of 74 kboepd; current rates reached >90 kboepd 2018 YTD Q1 opex of $18.8/boe (constrained Catcher production) 2018 YTD Kakap sale completed; Babbage sale announced 2018 YTD Levels of >60 kbopd reached; excellent delivery capacity of available wells 2018 Outlook FY Guidance of 80-85kboepd 2018 Outlook FY guidance of opex $17-18/boe and capex of $380m 2018 Outlook Complete Pakistan, Babbage and ETS sales 2018 Outlook Gas export to start shortly; complete drilling programme Tolmount Sea Lion Exploration Net Debt 2018 YTD Significant progress; contract awards ongoing 2018 YTD Negotiating funding packages; LOI signed with contractors 2018 YTD Significant licence awards in Mexico, Indonesia; exited final E.ON commitments 2018 YTD Q1 cash flow neutral; net debt down post CB exchange 2018 Outlook Project sanction scheduled for second half 2018 Outlook Secure funding for the project ahead of FID 2018 Outlook Zama appraisal drilling to start in H2 (including on adjacent Pemex block) 2018 Outlook Significant cash flow generation, debt reduction and improving covenant leverage ratio May 2018 P2
The asset portfolio Largest 5 fields accounted for c. 70% of production in 2017 May 2018 P3
Strategic framework, NAV focused Debt reduction Priority in 2018/2019 Targeting 2.5x EBITDAX by end Q1 2019 Producing assets Core operations in UKCS and Natuna Sea Maintain cost base of <$20/boe Discretionary spend of $100m per annum Development Continue to leverage FPSO expertise Targeting >20% IRR at $65/bbl Utilise leasing and other off balance sheet structures Exploration Focus on proven but underexplored basins Avoid high cost, deep-water areas Minimise upfront commitments May 2018 P4
Balanced capital allocation, returns driven 7 year capital allocation 2018-2024 Net operating cash flow Debt reduction 100% 30% Producing assets 20% New projects 40% Exploration 10% A sustainable position At $65/bbl the business will deliver Positive free cash flow in all years to 2024 Production > 100 kboepd at period end Covenant level of <1x at period end May 2018 P5
Portfolio overview
Asia production portfolio Chim Sáo (op, 53.125%) Natuna Sea Block A (op, 28.67%) Producing >30 kboepd Active well intervention programme Net production > 17 kboepd currently Ongoing reservoir optimisation Crude sold at premium to Brent GSA1 market share increasing Improving gas price BIGP first gas 2019 Optimise exploitation of Lama gas Long life, low opex assets May 2018 P7
UK production portfolio Reserves upgrade FPSO lease extended and rate reduced Looking at well optimisation Current production c. 8 kboepd High uptime; steady 5 kbopd Infill drilling 2020 Potential 3rd party business Huntington (op, 100%) Solan (op, 100%) UK production >50 kboepd 2019-22 Elgin-Franklin (5.2%) B Block (op, various) One of the UK s largest producing fields Long field life (COP 2035+) Active well intervention programme Exploration upside Targeting deferral of COP to 2021 Continuing positive cash flow May 2018 P8 Tax advantaged cash flows
Catcher the journey to first oil What we achieved in 2017 FPSO hull and topsides completed and integrated Sailaway of FPSO from Keppel yard HSE Acceptance of Safety Case Drilling and completion of 6 wells Successful tie-in of wells and deployment of subsea control pods Hook up of STP buoy to FPSO Successful pull in of all risers, umbilicals and installation of swivel stack First Oil achieved 23 Dec 17 May 2018 P9
2017 successful full cycle delivery of Catcher Experienced project management team in delivery of FPSO projects World class contractors Early operations involvement in project Collaborative and strong relationship with key contractors Deployment of industry leading technology e.g. Geosteering On schedule Forecast total capex 30% below budget Plateau production increased by 20% Industry leading outcome on HSE Experienced well delivery team Subsurface design optimisation Favourable market conditions May 2018 P10
Catcher Area commissioning status Dec 2017 Oil treatment plant Jan 2018 Booster gas compression Feb 2018 Gas treatment plant Mar 2018 Gas lift and export compression May 2018 60 kbopd production Operations Good uptime; oil plant up and stable Water injection commissioned Production levels reached >60 kbopd Gas export to start imminently All 3 fields on-stream and excellent deliverability May 2018 P11
Catcher Area upside 16 of 18 wells now completed Latest Catcher well (CCP8) higher net pay than prognosed Potential for reserves upside Conservative initial recovery factor assumed Positive production test results Well-connected sands with good pressure support Reservoir quality and sand quantity above predictions made at sanction Infill drilling opportunities 4D seismic acquisition targeted for 2019 Tie-back of near field discoveries Laverda, Catcher North Laverda: Tie-back via Varadero Varadero Infill FPSO Catcher North: Joint development with Laverda Catcher Infill: Multiple future Cromarty and Tay targets identified March 2018 P12 Burgman Infill: Burgman Far East target Supported by seismic and well results
Tolmount high value project Adds significant resource 540 bcf (100 mmboe) Provides next phase of UK growth 50 kboepd peak production Low capex requirement $100m (Premier s share) Low life of field total project cost $20/boe Indicative production profile boe equivalent (kboepd) 60 50 40 30 20 10 0 Generates significant tax advantaged cash flows; >$1bn of net cash flow Tolmount 48 km to terminal Potential Area Recovery of c. 1Tcf Holderness Inshore MCZ Holderness Offshore MCZ Onshore Terminal May 2018 P13
Tolmount Main project update 2017 highlights Key terms agreed for funding of Tolmount facilities Draft Field Development Plan submitted to OGA Final documentation with selected contractors for platform construction, pipeline and terminal modifications being completed Regulatory, environmental and planning statements submitted for public consultation Project sanctioned scheduled for 2018 2H Infrastructure joint venture Dana and CML will jointly own the platform and export pipeline Tolmount gas will use the facilities in return for production based tariff Premier s share of total capex reduced to $100m Infrastructure Owners Onshore terminal 26% SURF 19% CAPEX Sources Platform 16% Drillex 25% Owners 14% Tolmount Owners May 2018 P14
Tolmount Area Development 2018 Sanction Tolmount Main New 3D seismic over Greater Tolmount Area Tolmount East Subsea well tie-back 220 Bcf Extends Tolmount Main plateau SW 42/28d-12 NE 2019 Construction of platform, pipeline, onshore mods starts Appraise Tolmount East Gas water contact Tolmount Tolmount East 2020 1 st development well on Tolmount Main Exploration well on TFE Mongour 2021 2022 May 2018 P15 3 development wells on Tolmount Main Sanction Tolmount East 1 st gas from Tolmount East development Tolmount Main NUI and 4 wells 540 Bcf $100m (net) capex Tolmount Far East (TFE) 150 Bcf Subsea well tie-back 3rd party opportunities Platypus
Annual average oil rate (kbopd) Sea Lion substantial progress 1 3 World scale resource 1 bn bbls in new province Well understood reservoir Highly marketable crude 160 140 120 100 80 60 40 20 0 World class contractor team Phase 2 Phase 1 0 5 10 15 20 Years from first production 2 Proven development concept Technically straightforward FPSO development (similar to Catcher) Extensive project development and engineering complete Supply chain and logistics proven after drilling campaign Experienced in comparable projects Leveraging on past relationships and delivery of Catcher Opportunity to lock in supply chain at competitive rates Contractor interest aligned via provision of vendor financing 4 Regulatory interface well-advanced Environmental Impact Statement public consultation process nearing completion FDP substantially agreed; final update at sanction Alignment with FIG on key fiscal, commercial and regulatory items Key metrics Sea Lion Ph1 Catcher Development Plan FPSO+SPS FPSO+SPS FPSO oil capacity 85 60 FPSO liquid capacity 120 125 Drill Centres 1-2 3 Total wells 23 19 Producers 16 15 Injectors 6 4 Pre-first oil capex $1.5bn $1.3bn Reserves/resource 220 96 May 2018 P16
Sea Lion 2018 targets Select preferred contractors and secure vendor financing LOIs signed for c. $1.5 bn of total contracts value Owners Costs Drilling rig Well services Subsea equipment Subsea installation services Logistical support >$400m of vendor loan notes Subsea Pre-first Oil capex $1.5bn Wells Secure senior debt funding Export credit agencies and project finance providers Working towards year-end final investment decision 25% Upstream partnership 50% Export credit / bank finance 25% Vendor financing May 2018 P17
Refocused exploration portfolio Repositioned towards emerging plays in proven hydrocarbon provinces Early success in Mexico at Zama; looking to increase acreage footprint Managed position in Brazil to focus on Ceara Basin; high impact prospectivity identified Capture of Andaman II licence offshore Indonesia Retained high value infrastructure led exploration opportunities close to P&D assets Exited frontier and mature areas Rationalised E.ON portfolio Significantly reduced commitments Prospect Y Prospect X Early mapping of Andaman II Andaman II location map Prospect Z 3Km May 2018 P18
Mexico 2015: Awarded Blocks 2 and 7 in Mexico Round 1.1 2016: Increased interest in Block 7 to 25% 2017: Zama-1 discovery made on Block 7 400-800 mmbbls 1 (P90-P10); API 30 2018: Awarded 3 blocks in Mexico Round 3.1 Block 30 (Sureste Basin); Blocks 11 and 13 (Burgos Basin) 2018/2019: Zama appraisal programme Potential appraisal locations Pemex to spud Asab-1 in Q3 2018 3 1 Zama 1. Northern, tests OWC, water sample 2. Southern, tests reservoir continuity/ variability 3. Crestal, DST, isopach thick (potential location of Asab-1 Pemex well) 2 1 includes those volumes that extends into the neighbouring block
Indicative full field Zama development Indicative development metrics P50 resource 600 mmbbls Capex +/- $1.8bn (operator estimates) Peak production 100-150 kboepd First oil 2022/23 2018 Appraisal and pre-feed 2020 2019 FEED Development FID 2022/3 First oil May 2018 P20
Wahoo, Block 30, a Zama Analogue? Zama Block 7 seismic at time of licensing (2015) Wahoo Block Block 30 seismic at time of licensing (2018) Wahoo flat spot Zama flat spot 1. Identical trapping geometry 2. Down dip amplitude shut off 3. Similar age reservoirs 4. Evidence of a clear flat spot
Tuna, Indonesia (65%, operator) Highlights Discovered in 2014; >90 mmboe Evaluation of potential development scenarios ongoing Government agreement signed with Vietnam and Indonesian governments re: connection to existing infrastructure in Vietnam Farm out process launched ahead of 2019 appraisal campaign Granted 3 year extension to exploration period of licence May 2018 P22
Ceara Basin, Brazil High impact prospects in stacked targets matured for drilling Berimbau/Maraca (Block 717) 661 Itarema/Tatajuba (Block 661) Drilling operations planned for late 2019/2020 Option to extend licences until July 2021 2 well programme targeting >2 Bn bbls STOIIP Block 717 Block 661 A B B A B B 1-CES-075 4-CES-128 1-CES-160 A 10km N 038 Maastrichtian/ Campanian Berimbau 041 Turonian/ Cenomanian 044 Albian Itarema Complex Tatajuba 041 Turonian/ Cenomanian 044 Albian Maraca K40 090 Trairi A 10km 061 Aptian 8km Data Proprietary to PGS Investigacoa Petrolifera Limitada 8km 090 Trairi Data Proprietary to PGS Investigacoa Petrolifera Limitada May 2018 P23
Financials
Hedging Hedging policy 30-50% of future oil and gas volumes on a rolling 12-18 month basis Minimum required under lender agreement is 20% Liquids hedging Progressively increased as oil price rose 50% of 2018 oil production hedged 60% of 2018 oil production exposed to upside UK gas hedging 27 per cent of remaining 2018 UK gas volumes hedged at an average price of 45 pence/therm Oil hedging Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Swaps / Forwards Volumes 40% 40% 40% 28% 28% 21% Av. price $58/bbl $60/bbl $60 /bbl $66/bbl $67/bbl $67/bbl Additional options in Q2 and Q3 2018 with an average floor price of $56.3/bbl May 2018 P25
Portfolio management Seek opportunities with strategic fit within existing geographic units Focus on operated long-life assets Material working interest Critical mass locally UK tax optimisation Covenant accretive Dispose of non-core assets to accelerate debt repayment 2018 highlights and outlook Announced sale of Babbage Area assets to Verus Net cash proceeds of $64 million Verus will take on exploration commitments valued at $24 million Sale of interest in Kakap completed ETS asset sale expected to complete in June Completion of the sale of Pakistan to Al-Haj Group remains subject only to approvals from Pakistani authorities May 2018 P26
2018 FCF profile, capex and abandonment Stable operating cost base at $17-18/boe P&D, exploration & abex spend of $380m Continuing to defer COP dates across portfolio UK tax history shelters UK abandonment costs Early exchange of convertible bonds Debt reduction accelerates through year Q1 free cash flow neutral; significant debt reduction forecast in H2 with Catcher on plateau Return balance sheet to investment grade metrics by year-end 2018 Covenant leverage ratio forecast to fall to 3x EBITDA by year end at current oil prices 300 200 100 2018 P&D capex ($m) 120 80 40 0 Q1 Q2 Q3 Q4 2018 P&D capex and exploration ($m) - UK producing BIGP Chim Sao Catcher Tolmount, Sea Lion Exploration May 2018 P27
2017 Financials 12 months to 31 Dec 2017 12 months to 31 Dec 2016 Production (kboepd) 75.0 71.4 Opex per Barrel ($/boe) 16.4 15.8 P&L and cash flow $m $m Sales revenue 1,102 983 Net (loss)/profit (254) 123 Operating cash flow 496 431 Interest and fees (309) (152) Capex (275) (663) Abandonment (26) (16) Decom pre-funding (17) (61) Disposals/(Acquisitions) 202 (119) Net cash flow 71 (580) 20 Realised prices 2017 2016 Oil (post hedge) ($/bbl) Opex ($/boe) 30 52.1 52.2 UK gas (p/therm) 47.2 47.6 Indonesia gas ($/mmscf) Production (kboepd) 40 30 20 10 0 UK 8.4 7.8 2017 2016 Indonesia Vietnam Pakistan 2017 2016 Balance sheet 10 Accounting net debt 2,724 2,765 May 2018 P28 0 UK Indonesia Vietnam Pakistan
May 2018 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