Investor Presentation November 2017 Forward-looking statements - - PowerPoint PPT Presentation

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

YTD

Production average ytd 76.6 kboepd Cost Base

YTD

Opex of $15.9/boe; FY capex guidance reduced to $300- 310m Disposals

YTD

Wytch Farm and Pakistan sales announced; other processes ongoing Catcher

YTD

FPSO arrived in the field - commissioning underway; positive drilling results Tolmount

YTD

HoT signed with infrastructure partner; draft FDP submitted to OGA Sea Lion

YTD

Negotiating funding packages Exploration

YTD

World class oil discovery at Zama-1, Mexico Net Debt Reduction

YTD

Positive cash flow in H1; ytd in line with forecast

November 2017 | P3

Full Year Target

FY Guidance remains to 75-80 kboepd

Full Year Target

Deliver FY guidance of

• pex 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

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

Production overview

Largest 5 fields account for c. 70% of production

November 2017 | P4

Development portfolio

>800 mmboe

• f discovered

but undeveloped reserves and resources

November 2017 | P5

Delivering on our strategy

• Opportunistic acquisitions
• $16/bbl
• Operated
• FPSO’s
• Partner-funded
• Proven basins
• Under drilled
• 77 kboepd

Value

Stakeholder Returns Debt Reduction

• Disposals – realising value

Production Costs Development Exploration Portfolio Management Acquisitions

November 2017 | P6

Future plans

Balance Sheet Management

Value

Stakeholder Returns Debt Reduction Production Operating Costs Development Exploration

• $15-$17/bbl
• Catcher
• Tolmount
• Sea Lion
• Zama
• Tuna
• High value,

near field

• Material upside

in Mexico and Brazil

• Continuing

growth

• Reserve life >10 yrs
• Free cash flow 2018-2022 reducing debt
• Net debt : EBITDA <3x

Portfolio Management – Acquisitions

• Disposals by majors
• Tax optimisation

Portfolio Management – Disposals

• Non core assets
• Mitigating risk

November 2017 | P7

Producing Portfolio

Chim Sáo, Vietnam (53.125%, operator)

20P 5IPST1

2017 ytd

• 15.0 kboepd
• High operating efficiency and strong
• Strong reservoir performance
• $9/boe operating cost
• 1st infill well completed and tied-in

Outlook

• Further infill well planned before year end

5 10 15 20 25 30 35 2016 2017 2018 2019 2020 Current Previous Improved Production Profile kboepd (gross)

59 mmboe reserves remaining

55 mmboe at sanction 57 mmboe produced to date 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%
• f 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

20 40 60 80 100 5 10 15 20 2016 2017 2018 2019 2020 NSBA Production net to PMO (kboepd) Market Share GSA1 (%)

BIGP

30% IRR

93 Bcf $340m gross capex

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

P1 W2 P2 W1 500m

Top Solan Sand Depth Map

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

September 2017 | P15

Catcher – on schedule for start up by year end

• 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

• All 12 wells planned pre-first oil now

complete confirming good quality oil

• Subsea activities complete; short campaign

to support hook-up and commissioning

• perations post arrival of FPSO

Project capex down 29% on sanction

November 2017 | P15

Catcher 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

Gas export line – commissioned prior to start up Teekay shuttle tanker

Cone Plug Removal

Arrival in the UK and Hook-Up 4-6 Weeks Commissioning 3-4 Weeks Harbour On location

Risers Umbilical's ESDV’s* Swivel Stack Reinstate- ment Commiss- ioning Pre-Commiss- ioning Buoy Hook-Up November 2017 | P16

10,000 20,000 30,000 40,000 50,000 60,000 70,000 Daily Oil Potential (stb/d) Catcher Varadero Burgman

Catcher Commissioning & Production Profile

• Catcher is the initial field on production due to it’s ability to produce oil in a stable fashion for the first stages
• f 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

Fuel Gas Import Catcher First Oil Oil Stabili- sation Fuel Gas Varadero First Oil Permeat. Comp Water Injection Gas Lift Gas Export Comm. Burgman First Oil Flash Gas Comp Primary Gas Handling Produced Water

November 2017 | P17

Improved production profile anticipated

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

Varadero Catcher Burgman

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

Estimated Tolmount Capex (Gross) $m Development Scope Gross Capex (Real, $mm) % pre 1st 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

• High return

project robust down to low gas prices

PMO 19% Dana 50% CML 31%

Capex Split

(1) an Antin Infrastructure Partners portfolio company (2) Based on plan where one well is on-stream pre-1st gas

November 2017 | P19

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

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

Perenco Dimlington SNSPS (Cleeton / Ravenspurn) West Sole (connected to Perenco Easington) Tolmount Centrica Easington Rough & York

Dimlington Terminal >1 bcf gas processing capacity, 600 mmscfd installed compression capacity plus additional condensate processing Tolmount

Gassco Langeled Ormen Lange

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 3rd party business potential

• A new hub with 20+ year life

Tolmount Mongour Tolmount East Tolmount Far East

Tolmount area ~ 1 Tcf

Indicative production profile

42/28d-12 NE SW Tolmount Tolmount East

Tolmount Far-East Gas water contact

November 2017 | P21

ENSCO 8503 Flat Spot

• 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

Full stack reprocessed seismic data in depth E W Zama-1 Well Good conformance of seismic amplitude with structural contours

Zama-1 oil discovery - volume estimates

Gross oil bearing interval to scale

November 2017 | P22

Potential to leverage Mexican fabrication capability

Zama – illustrative development scenario

Location of Zama discovery Indicative development metrics Resources 400-800 mmboe1 Daily peak production 100-150 kbopd Capex +/- $1.8 billion Appraisal 2018-19 First oil 2022-23 Block 7 prospect map Zama

(1) Including the extension onto the neighbouring block Amoca

Zama

Hokchi

November 2017 | P23

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

Sea Lion, Falkland Islands (60%, operator)

20 40 60 80 100 120 140 160 5 10 15 20 Annual average oil rate (mbopd) Years from first production Phase 2 Phase 1

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 km2 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-661 CE-M-665 CE-M-717 Excellent imaging on new broadband seismic

• f Upper Cretaceous

turbidite channel sands

Maraca K40 Ganza K40 Pecem K40 Berimbau Up-dip pinch out and fault offset Berimbau Pecem K50 discovery 1-CES-158 1-CES-112 SW NE

CE-M-717

Data Proprietary to PGS Investigacoa Petrolifera Limitada

8km

November 2017 | P26

Financials

Net debt and hedging

Drawn Debt Total Facilities (incl cash)

Cash & Undrawn

$4.0 bn

Facilities confirmed 1

$3.4 bn 1,000 2,000 3,000 4,000 2017 2018 2019 2020 2021 2022

Previous Revised

Maturities extended 1

1 FX as at when facilities entered into

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

Comprehensive refinancing completed 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

Q4 2017 H1 2018 H2 2018 Oil hedges % Hedged Price ($/bbl) % Hedged Price ($/bbl) % Hedged Price ($/bbl) Fixed price oil hedges 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

Liquids and UK gas hedging as at 31 October

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

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

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

Portfolio management

2014-2017

• Over $350m realised from disposals
• Significant value created through E.ON

acquisition

2018-2020

• Further disposals to accelerate deleveraging

Financial outlook

November 2017 | P29

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 www.premier-oil.com November 2017