2017 Half-Year Results 24 August 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. August 2017 | P1
Agenda 2017 delivery Tony Durrant Financial results Richard Rose Producing and development portfolio Robin Allan Outlook Tony Durrant August 2017 | P2
2017 – a year of strong delivery Production Cost Base Disposals Catcher 1H Highlight 1H Highlight 1H Highlight 1H Highlight Record production of Opex of $14.7/boe; Wytch Farm and FPSO on schedule; 82.1 kboepd FY capex guidance Pakistan sales positive drilling reduced to $325m announced results Full Year Target Full Year Target Full Year Target Full Year Target Target further FY Guidance increased Realise >$300m from Deliver first oil by year reductions; deliver FY to 75-80 kboepd disposals end guidance of opex <$16/boe Tolmount Sea Lion Exploration Net Debt Reduction 1H Highlight 1H Highlight 1H Highlight 1H Highlight HoT signed with Negotiating funding World class oil Positive cash flow infrastructure partner packages discovery at Zama-1, reducing net debt Mexico Full Year Target Full Year Target Full Year Target Full Year Target Progress financing and Define appraisal and Generate positive net Progress for Premier commercial initiatives development plans for cash flow post Board approval in Q4 Zama disposals August 2017 | P3
Financial results Richard Rose
Financial highlights 1H $566 million Revenue 1H 2016: $394 m Operating $292 million 1H 2016: $108 m Cash Flow $14.7 /boe Operating Costs 1H 2016: $16.5/boe $41 million Profit After Tax 1H 2016: $167 m * $136 million Capex 1H 2016: $319 m $52 million Free Cash Flow 1H 2016: $(433) m $2,739 million Net Debt Y/E 2016: $2,765 m * Includes E.ON negative goodwill credit of $106.9 million August 2017 | P5
Positive cash flow in 1H 6 months 6 months Capital expenditure ($m) to 30 June to 30 June 400 2017 2016 Abandonment 325 Development 300 Working Interest production (kboepd) 82.1 61.0 Exploration 200 Entitlement production (kboepd) 76.1 57.0 136 Realised oil price (US$/bbl) – post hedge 49.9 48.6 100 Realised Indonesia gas price (US$/mcf) – post 8.6 5.8 0 1H 2017 FY 2017 hedge Realised UK gas price (p/therm) – post hedge 46 41 2H 2017 liquids and UK gas hedging $m $m Oil hedges % hedged Price ($/bbl) Cash flow from operations 336 145 Fixed price oil 21 % 52.4 hedges Taxation (44) (37) Oil option sales 25 % 51.1 Operating cash flow 292 108 UK gas hedges % hedged Price (p/therm) Capital expenditure (136) (319) Fixed price 37 % 47 Decommissioning cash escrow (8) (56) Opex ($/boe) Acquisitions / disposals 30 (111) 2015 2016 1H 2017 2017F Finance and other charges, net (126) (55) UK 30.0 24.4 19.9 21.4 Net cash in (out) flow 52 (433) Indonesia 10.0 10.1 8.7 10.1 Pakistan 3.7 3.7 3.8 4.0 Vietnam 11.7 8.7 9.0 10.9 Net Debt (2,739) (2,635) Group 15.5 15.8 14.7 15.9 August 2017 | P6
Net debt and refinancing Net debt Comprehensive refinancing completed Facilities confirmed 1 • Net debt of $2.7bn, reduced from YE2016 $4.0 bn Cash & position $3.4 bn Undrawn • Net debt/EBITDAX (1) ratio of 4.5x at 30 June 2017 Drawn Debt Total Facilities • >US$500mn of cash and undrawn facilities (incl cash) Maturities extended 1 at 30 June 4,000 Previous Outlook Revised 3,000 • Cash flow positive for FY including planned 2,000 disposals; debt reduction accelerating once 1,000 Catcher on-stream 0 2017 2018 2019 2020 2021 2022 • Average cost of debt c7% going forward 1 FX as at when facilities entered into • Targeting Net Debt/EBITDAX <3x by end 2018 Other key amended terms • Covenant profile re-set with headroom • Sufficient headroom to deliver Catcher, • Enhanced economics (~1.5%) to lenders • A warrant package to lenders Tolmount and selective new investments • Convertible bond re-priced • Corporate governance controls (1) – Net debt in covenant calculation includes LCs August 2017 | P7
Financial outlook Operating Costs Capex 2014-2017 2014-2017 • Down from c$20/boe to <$15/boe • Reduced from over $1.0bn pa. to $325m in • Over $300m of absolute cost savings 2017 • Reduced forward commitments delivered since 1/1/2015 2018-2020 2018-2020 • Stable operating cost base at current levels • Maintain at current run rate depending on new $15-17/boe projects • Disciplined approach to capital allocation Portfolio management Net debt 2014-2017 2014-2017 • Over $350m realised from disposals • Increased due to investment and weakness in oil price • Significant value created through E.ON • Reducing by end 2017 acquisition 2018-2020 2018-2020 • Further disposals to accelerate deleveraging • Leverage ratio below 3.0x and falling • Priority remains reduction in absolute levels of net debt August 2017 | P8
Producing and development portfolio Robin Allan
Production overview UK accounts for c. 55% of production Largest 5 fields account for c. 70% of production August 2017 | P10
Development portfolio >800 mmboe of discovered but undeveloped reserves and resources August 2017 | P11
Catcher – on schedule for start up by year end • All 12 wells planned pre-first oil now • Marine trials underway • Sailaway to North Sea complete confirming good quality light oil • Subsea activities complete; short campaign imminent • On schedule for 2017 first oil to support hook-up and commissioning • Important cornerstone of operations once FPSO is installed Premier’s debt reduction Project capex down 29% on sanction August 2017 | P12 August 2017 | P12
Catcher – continuing positive drilling results • 12 wells completed to date (4 on each of Varadero Catcher, Varadero and Burgman fields) • 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 Catcher • Improved production profiles anticipated of c.60 kboepd Burgman • Review of FPSO capacity underway Improved production profile anticipated Plateau production up 20% on sanction August 2017 | P13
Tolmount – infrastructure partnership • Partnership with Dana Petroleum and CATS Management Ltd (1) PMO • Dana and CML will jointly own: CML 19% 31% – platform Capex – export pipeline Split • Tolmount gas will use the facilities Dana – LoF tariff 50% • 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 Estimated Tolmount Capex (Gross) $m % pre 1 st gas Development Scope Gross Capex (Real, $mm) 100% Platform 90 100% High return SURF (20” pipeline to beach) 100 project robust 85% Host Terminal modifications 150 down to low Drilling (2) 64% 140 gas prices 92% PMT 70 - Total 550 (1) an Antin Infrastructure Partners portfolio company (2) Based on plan where one well is on-stream pre-1 st gas August 2017 | P14
Tolmount – progressing on schedule for FID in 1H 2018 • Development concept selected Q1 Dimlington Terminal >1 bcf gas processing capacity, 600 mmscfd installed compression capacity • Initial phase: targeting 540 Bcf resources plus additional condensate processing • Peak production capacity 300 MMscfd Tolmount • FEED contracts awarded; engineering underway • Tendering of major project scopes to Perenco Dimlington SNSPS commence shortly (Cleeton / Ravenspurn) • Timing: Centrica Easington West Sole Rough & York (connected to – Board approval Q4 &FID 1H 2018 Perenco Easington) Gassco Langeled – First gas 2020 Tolmount Ormen Lange 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 August 2017 | P15
Tolmount – future phases planned Tolmount East • Subsea tie-back or small platform • 2019 well planned to confirm resource Tolmount area Tolmount Mongour Tolmount Far East Far East ~ 1 Tcf • Subsea tie-back or small platform to Tolmount or Tolmount East Tolmount East Mongour • Subsea tie-back or extended reach well from Tolmount East 3rd party business potential • A new hub with 20+ year life Tolmount Indicative production profile SW NE 42/28d-12 Tolmount Far-East Gas water contact Tolmount Tolmount East August 2017 | P16
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