Investor Presentation January 2018 Forward-looking statements This - - PowerPoint PPT Presentation

Investor Presentation

January 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.

January 2018 | P1

Executive Summary

2017 – a year of strong delivery

Production

2017

Production 75.0 kboepd, in line with guidance Cost Base

2017

Opex of $16.5/boe; FY capex $305m below revised guidance Disposals

2017

Wytch Farm completed; Pakistan and ETS pipeline sales announced Catcher

2017

First oil delivered on 23 December. On schedule and c30% below budget Tolmount

2017

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

2017

Negotiating funding packages; LOI signed with contractors Exploration

2017

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

2017

Positive cash flow in the year; deleveraging underway

2018 Target

Guidance 80-85 kboepd (Catcher ramp up and 2017 disposals)

2018 Target

FY guidance of opex c$17-18/boe and capex (ex-Abex) of $300m

2018 Target

Complete Pakistan and ETS sales; other processes ongoing

2018 Target

Deliver production ramp up to 60,000 bopd; complete wells

2018 Target

Progress for FID in 2018

2018 Target

Progress financing, fiscal and commercial initiatives

2018 Target

Appraise Zama in H2/early 2019 and define development plans

2018 Target

Generate positive net cash flow and target debt reduction to 3x Net Debt/EBITDA

January 2018 | P3

Production overview

Largest 5 fields account for c. 70% of production

January 2018 | P4

Development portfolio

>800 mmboe

• f discovered

but undeveloped reserves and resources

January 2018 | P5

Delivering on our strategy

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

Value

Stakeholder Returns Debt Reduction

• Disposals – realising value

Production Costs Development Exploration Portfolio Management Acquisitions

January 2018 | P6

Future plans

Balance Sheet Management

Value

Stakeholder Returns Debt Reduction Production Operating Costs Development Exploration

• $17-$18/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

January 2018 | P7

Producing Portfolio

Chim Sáo, Vietnam (53.125%, operator)

20P 5IPST1

2017

• 14.9 kboepd
• High operating efficiency and strong

reservoir performance

• $9/boe operating cost
• 2 infill wells completed; 6,500 boepd (gross)

production added

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 January 2018 | P9

Natuna Sea Block A, Indonesia (28.67%, operator)

2017

• 12.9 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

January 2018 | P10

Huntington, Central North Sea (100%, operator)

2017

• 13.0 kboepd, 28% above budget

− High FPSO operating efficiency − Strong reservoir performance − HoT agreed on lease extension and extended Shell term deal Outlook

• Maximise production

Currently producing ~13 kboepd

January 2018 | P11

Solan, West of Shetlands (100%, operator)

2017

• 5.9 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

January 2018 | P12

Elgin-Franklin, Central North Sea (5.2%)

2017

• 5.4 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

January 2018 | P13

Portfolio Potential

September 2017 | P15

Catcher – first oil achieved 23 December

• Arrived in North Sea in October
• Hook up and Commissioning

programme executed in c. 2 months

• First Oil from Catcher field

achieved 23 December and from Varadero on 12 January

• Phased ramp up of production

underway

• Important cornerstone of

Premier’s debt reduction

• All 12 wells planned pre-first oil completed

confirming good quality oil

• Subsea activities complete including short

campaign to support hook-up and commissioning

• perations post arrival of FPSO

Project capex down 29% on sanction

January 2018 | P15

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

Catcher Final 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

January 2018 | P16

Improved production profile anticipated

Catcher – continuing positive drilling results

• 14 wells completed to date

– 4 on each of Catcher, Varadero and Burgman fields planned pre first oil – Phase 2 drilling on Catcher underway

• 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

January 2018 | P17

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

January 2018 | P18

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

• Evaluation of proposals received for major

project scopes (including platform and pipeline) underway

• Draft FDP submitted to OGA
• Timing:

– FID 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

January 2018 | P19

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

January 2018 | P20

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

January 2018 | P21

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

January 2018 | P22

Project status

• 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)

• LOIs signed with contractors

Outlook

• Positive commercial and fiscal

engagement with FIG

• Positive engagement with contractor

market and senior debt providers

• 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

January 2018 | P23

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

January 2018 | P24

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

January 2018 | P25

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 $2.7bn
• Positive cash flow in 2017 including disposals;

debt reduction accelerating as Catcher production ramps up

• 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

January 2018 | P27

Liquids and UK gas hedging as at 31 December

• 40% of 2018 oil production hedged:
• 10% with options, floor price $55/bbl
• 30% swaps and fixed term sales, average

price $57/bbl

• 24% of 2018 UK gas production hedged at

47p/therm

Capex

2014-2017

• Reduced from over $1.0bn pa. to $305m 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

$17-18/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

January 2018 | P28

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 January 2018