investor presentation - devex conference presentation may contain forward-looking statements and...

Investor Presentation

May 2016

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 2016 | P1

Executive Summary

Acquisition of E.ON’s UK North Sea assets completed On-going asset disposals

2016 – progress against targets

On track to deliver at or above upper end of FY guidance of 65-70 kboepd 88% operating efficiency in Q1

Opex tracking 10-20% below budget; expected FY opex of c. $17/boe Gross G&A on track to deliver 10% reduction on 2015 (ex E.ON)

Solan on-stream 12 April, >14 kboepd tested from P1 P2 expected on-stream by mid-year

Pre-first oil capex 15% lower at $1.35 bn; first oil on schedule for 2017 FPSO delivery to Singapore by July; targeting subsea work completion by Q4

Net debt of $2.68 bn at end April; 2016 capex spend front-end loaded Expect to be cash flow positive at oil prices above c. $50/boe in Q4

Discussions ongoing with lenders to secure financial covenant waiver if required

May 2016 | P3

Maximise production

Further cost reductions

Solan on plateau (20-25 kboepd)

Progress Catcher

Focus on net debt

Manage covenant headroom

Refocusing the portfolio

Focus on Advantaged Assets

• UK, SE Asia, Falklands • Disposal of non-core assets • Appropriate balance of current cash flow,

development projects and longer-term upside

Looking forward

Strategy

Accelerate Debt Reduction • Take necessary corporate actions to

minimise net investment in 2016 (as in 2015)

• 2017 will see de-leveraging at the current forward curve

Continue Focus on Cost Base • Further opex and G&A savings in 2016 • Current and future capex spend

reductions

Financial Position

200

300

400

500

FY 2014(actual)

2015Budget

FY 2015(actual)

2016Budget

Solan, Huntington

100

200

300

400

FY 2014(actual)

2015Budget

FY 2015(actual)

2016Budget

G&A ($mm)

Opex ($mm)

May 2016 | P4

Looking forward

Proven Track Record in Acquisitions/Divestment • 6 separate transactions since 2013, focused on

pre-development assets • E.ON portfolio added 70 mmboe at cost of <$2/bbl;

offers further opportunities for asset disposal

Portfolio Management

Quality 2019 Portfolio • 80-90 kboepd; $15/bbl opex; long life

assets • Balance sheet debt reducing rapidly

Highly leveraged to oil price recovery • Low cash cost base; low effective

tax rate • Costs re-set to a sub-$50 world • c. 850 mmboe of reserves and

resources

Forward Position

379

120

0

100

200

300

400

Divestments Acquisitions

$mm

Operating Cash flow

Capex & Abex

Operating Cash flow

Capex & Abex

Operating Cash flow

Capex & Abex

2017 2018 2019

0

200

400

600

800

1000

1200

1400

$40/bbl

$50/bbl

$60/bbl

$45/bbl

$55/bbl

$70/bbl

$60/bbl

$80/bbl

$70/bbl

$mm

Illustrative Base Case

May 2016 | P5

Asset update

Summary of asset upsides

UK – Premier • Upside in Huntington and Solan • Elgin-Franklin producing above budget • Opex and capex savings in Catcher

project • Potential reserve upgrade at Catcher • Targeting substantial cost reductions • Potential disposal strategies

Q1 2016 production 18 kboepd Q1 2016 opex $30/bbl

VIETNAM • Infill programme targeting

18 kboepd (2018) • Seeking further cost reductions • FPSO lease restructuring

Q1 2016 production 17 kboepd Q1 2016 opex $7/bbl

INDONESIA • Ongoing developments (BIGP, Tuna, Lama) • Seeking further cost reductions • Increasing market share over time (→60%) • Synergies with Block B

Q1 2016 production 14 kboepd Q1 2016 opex $9/bbl GSA1 market share 44%

PAKISTAN • Ongoing infill drilling • Sale process underway

2016 Q1 production 8 kboepd 2016 Q1 opex $3/bbl

FALKLAND ISLANDS • Targeting savings to reach 20%

IRR at $55/bbl • Seeking long term partner(s) • Mature phase 2 and 3 concepts

Sea Lion: current economics

20% IRR at $65/bbl

EXPLORATION • Plan for 2018 drilling

programmes

Mature Mexico and Brazil (Ceara Basin) drilling targets

May 2016 | P7

Pakistan (8.3 kboepd) • Well-established gas

producing fields • Generates positive, stable

cash flows • Formal sales process

ongoing

0

5

10

15

2015 Q1 2016

Current production – high operating efficiency

Indonesia (14.0 kboepd) • Singapore demand above

take or pay • GSA1 share 44%; above

contractual share of 40.9%

0

5

10

15

20

2015 Q1 2016

Vietnam (17.4 kboepd) • Delivering ahead of

expectations • High operating efficiency • Better than predicted

reservoir performance

0

5

10

15

20

2015 Q1 2016

Group •Maintained high

operating efficiency •E.ON delivered

17 kboepd in Q1 •New production

from Solan

0

10

20

30

40

50

60

70

80

2015 Q1 2016

FY GUIDANCE

Expect to be at /above

65 – 70 kboepd

North Sea (17.6 kboepd) • 99% OE and lower decline from

Huntington • Unplanned shutdown on B Block • Solan on-stream April • E.ON production consolidated

from 28 April

05

10152025

2015 Q1 2016

OE 90%

OE 88%

OE 83%

Production (kboepd) Production (kboepd)

Production (kboepd)

Production (kboepd)

OE 70%

OE 87%

OE 96%

OE 93%

OE 90% OE

95% OE

95%

May 2016 | P8

Solan + E.ON

UK – production growth

• Averaged 17.6 kboepd in Q1 2016

• Group production growth driven by UK: E.ON assets, new Solan production and Catcher

• Continue to target substantial cost savings; opportunity to generate operating and cost synergies

• UK long life assets include Elgin-Franklin, Wytch Farm & Catcher

• $3.5 bn of UK tax losses and allowances and c. $550 m of Investment Allowances

May 2016| P9

Babbage

Balmoral Area Solan

Wytch Farm

Kyle Huntington

Elgin Franklin

0

10

20

30

40

50

60

70

80

90

100

Group BaseProduction

Solan 20-25 kboepd

E.ON 12-17 kboepd

Catcher 20-25 kboepd

South East Asia – reliable low cost production

Vietnam

• Strong Q1 2016 production and operating efficiency

– 32.8 kboepd (gross) production

– 96% operating efficiency

• Progressing further cost reductions

• Planning f0r future infill programme targeting unswept areas and low risk new reservoirs

Indonesia

• High operating efficiency and robust demand maintained production levels

– Market share exceeded contract

– Will increase as other suppliers decline

• Longer term, Indonesia (Batam) and Singapore are both seeking additional volumes

• Planning further developments to increase production beyond 2018

– Bison, Iguana, Gajah Puteri

– Lama exploitation

– Tuna

2015 operating

costs c.$13/bbl

2015 operating

costs c. $8/bbl

May 2016 | P10

Solan – first oil achieved, moving on to second oil

• P1 on-stream 12 April

– rates of 8 kbopd achieved from natural flow, rising to 14 kbopd with ESP

• Planned shut down ahead of second oil

– W2 tied in

– Final commissioning of water injection plant underway

– ESP completion for P2 being installed with tie-in planned for early June

• Utilise Superior Flotel to maximise workforce on platform to complete remaining systems

• Re-start production and ramp up to plateau rates of 20-25 kbopd

Plateau production

by Q3 of 20-25 kbopd

May 2016 | P11

Catcher – under budget and scheduled for 2017

Subsea

• 2015 subsea installation programme completed; 2016 programme underway

– Remaining templates installed

– Installation of bundles and riser system in progress

– Buoy and Mooring system to be installed over the summer

STB Buoy Underside of STB Buoy

15% lower pre-first oil

capex at $1.35 bn

Launching Catcher trailing towhead

Catcher towhead, Wick

May 2016 | P12

Catcher – under budget and scheduled for 2017

FPSO

• Hull fabrication accelerating in Japan and Korea

• Topsides and Turret fabrication advanced in ProFab, Dynamac and Asia Offshore yards

• Commencement of hull and integration work in Singapore from Summer 2016

Stern Terra Block; Japan

Aerial View of Catcher Modules; Singapore

May 2016 | P13

Fore Terra Block, Korea

• Ensco 100 rig on hire since July 2015

• 4 wells drilled with excellent operational performance

– two injectors (CTI1 and CCI2)

– Two producers (CCP3 and CTP1)

• Pre-drill predictions for reservoir depth, thickness and extent confirmed

• Reservoir quality and flow rates met or exceeded expectations

• Injector well tests demonstrated water injection capability into the field

• 4 further development wells planned for 2016

Catcher – initial drilling results encouraging

Well results confirm

high quality reservoir

Catcher CCP3 producer well

Catcher exploration well 29-1

Cromarty reservoir

0 500ft

May 2016 | P14

Final Investment Decision Timing

Will remain dependent on:

• Achieving attractive rates of return

• The outlook for long term oil prices

• The level of cost reductions secured

• Premier’s ability to fund project – without risking the balance sheet

Sea Lion complex – low cost option for large future value

• Phase 1 project economics enhanced

– 220 mmbbls from NE & NW areas of PL032

– 18 wells (13 pre-drilled) and 20 year field life

– $1.8 bn capex to first oil unchanged (costs down 30%)

• Conceptual design work completed

• Draft FDP submitted to FIG for comment

• Completed SPA amendment with RKH

• Phase 1 FEED is progressing cautiously

• Anticipate securing further cost reductions

• Looking to bring in additional upstream partner

Enhanced project

economics

Falling break-even

price

Subsea Installation

Subsea Prod’n System

Risers

FPSO

“Collaborative partnership”

“Collective costs incentives”

May 2016 | P15

North Falklands Basin – potential confirmed

Successful exploration programme now complete

• Zebedee discovery proves up additional resource to northern North Falklands Basin development

– Adds c. 60 mmbls resource to Sea Lion Phase 2

• Isobel Complex potential confirmed

– Potential for >480m oil column

– Multiple additional oil-bearing sands

• Programme curtailed due to rig performance issues

• Further appraisal concurrent with Sea Lion development

Sea Lion complex

520 mmbls; 2 phases

N Isobel Deep Geobody

Isobel Complex de-risked

May 2016 | P16

Finance

Strong cash flows despite lower oil prices

12 months to 31 Dec

2015 $m

12 months to 31 Dec

2014 $m

Working Interest production (kboepd) 57.6 63.6

Entitlement production (kboepd) 53.4 57.8

Realised oil price (US$/bbl) - post hedge 79.0 101.0

Realised gas price (US$/mcf) - post hedge 6.5 8.4

$m $m

Cash flow from operations 903 1,133

Taxation (94) (209)

Operating cash flow 809 924

Capital expenditure (1,070) (1,514)

Disposals 220 131

Finance and other charges, net (101) (120)

Dividends - (44)

Share buy back - (93)

Net cash in (out) flow (142) (716)

Net Debt (2,242) (2,122)

Capital expenditure ($m) Comprises proceeds from the sale of Block A Aceh and Norway and a positive adjustment from Scott area disposal Liquids hedging (incl E.ON)

2016 2017

Barrels hedged (mmbbls)

5.53 1.53

Average price ($/bbl)

67.0 45.8

2015 2016E

Exploration $216 c$100

Development $854 c$630

Total $1,070 c$730

May 2016 | P18

12 months to 31 Dec 2015

$m

12 months to 31 Dec 2014

$m

Sales and other operating revenues 1,099 1,629

Cost of Sales (661) (987)

Impairments (1,024) (784)

Gross profit/(loss) (586) (142)

Exploration/New Business (109) (84)

General and administration costs (14) (25)

Disposals 1 3

Operating profit/(loss) (708) (248)

Financial items (122) (136)

Profit/(loss) before taxation (830) (384)

Tax credit/(charge) (241) 174

Profit/(loss) after taxation (1,071) (210)

Income statement

Operating costs ($/boe)

Exploration write offs include Badada well in Kenya and uncommercial Bonneville discovery in UK

2014 2015 2016

UK $37.2 $30.0 $27

Indonesia $10.0 $10.0 $11

Pakistan $3.3 $3.7 $5

Vietnam $14.6 $11.7 $13

Group $18.5 $15.5 c$16-17

EBITDAX 752 1,074

$3.5 bn of UK tax losses and allowances

May 2016 | P19

200

300

400

500

FY 2014(actual)

2015Budget

FY 2015(actual)

2016Budget

Solan, Huntington

More than 250 further initiatives identified targeting savings of > $50m p.a

Cost reduction continuing

0

500

1000

1500

2014 2015 2016F 2017F 2018F

Committed capex profile ($mm)

P&D Capex

Exploration

Opex ($mm)

100

150

200

250

300

350

FY 2014(actual)

2015Budget

FY 2015(actual)

2016Budget

G&A ($mm)

• Contractor rate cuts • Contract renegotiations • G&A headcount

reductions of c20% • Discretionary capex/opex

cuts • Operating efficiencies • Lower cyclical costs

(fuel/insurance etc.)

• Further contractor rate cuts

• Additional contract renegotiations

– FPSOs – Logistics

• Collaboration with other operators

• Phasing of capex payments with suppliers

Initial Cost Reductions 2014/15 Further Actions

2016+

2015 Opex down 25% G&A down 25% 2016

Opex down 10-20% G&A down 10%

May 2016 | P20

Covenant compliance and mitigating actions

• E.ON UK asset acquisition materially covenant accretive

4.

• Covenant position amended – Net debt $2.2 billion (YE 2015) – Headroom > $900m (YE 2015) – Strong support from banks & bondholders

1.

• Key focus on compliance in low oil price environment

– Tested half yearly at 30 June and 31 Dec – Likely to require relaxation of covenants if

low oil price persists

2.

• Mitigating actions – Capex phasing, pre-paid oil sales, further

cost reductions, sale and leaseback, asset disposals

3.

Financing structure

• Corporate unsecured • No reserve base

determinations • No amortisations

Liquidity • $1.2 bn cash & undrawn facilities at year end 2015

• No maturities until end 2017

Cost of debt

• 60% fixed interest rate • Average debt costs of 3.5%

in 2015

307 362

1468

558

0

200

400

600

800

1000

1200

1400

1600

Drawn debt maturities (US$mm)

May 2016 | P21

End 2015 2P reserves and resources

Falklands Indonesia Mauritania Pakistan UK Vietnam Total

2P

On Production – 35.2 0.1 12.6 22.8 23.8 94.5

Approved for Development

– 12.7 – – 87.4 0.1 100.2

Justified for Development

136.0 1.1 – – – – 137.1

Total Reserves 136.0 49.0 0.1 12.6 110.2 24.0 331.9

2C

Development Pending

– – – – – – –

Development Unclarified / on hold

134.4 98.3 – 7.2 17.6 11.2 268.7

Development not viable

126.7 1.8 – – 21.3 7.2 157.0

Total Contingent Resources

261.1 100.1 – 7.2 38.9 18.4 425.7

Total Reserves + Contingent Resources

397.1 149.1 0.1 19.8 149.1 42.4 757.6

May 2016 | P22

Appendix

Rationale for the E.ON acquisition

• Strengthens Premier’s position in UK North Sea with its associated tax benefits; opportunity to generate operating and cost synergies

• Continues Premier’s track record of capturing long term value through acquisition at low points in the oil price cycle

• Adds stable UK gas revenues to the portfolio; rebalancing commodity exposure

• Adds high quality assets at a compelling valuation with a valuable hedging position in 2016 and 2017

– Assets acquired at $1.6/boe based on CPR estimate of 2P reserves vs. UK North Sea average of $13/boe (since 2000)

– CPR values the net asset value of 2P reserves and SNS infrastructure at $494 million (pre-tax) vs. purchase consideration of $120m

• Adds immediate cash generative production, tax synergies and material covenant accretion with rapid payback – meeting Premier’s stated acquisition criteria

Total 73 kboepd

Proforma 2015 Production

ProformaYE15 Reserves

Elgin-Franklin area

Huntington

Other CNS

Tolmount

Babbage area

Premier

Total 402 mmboe

Elgin-Franklin area

Huntington

Other CNS

Babbage area

Other SNS

Premier

May 2016 | P24

Huntington (38.5%, op.) • Existing Premier field, equity interest

increases to 100% • 2.5mmboe net reserves1 • 2016 ytd production: 5.2 kboepd (net),

in line with 2015

E.ON UK assets – strong start to 2016

Tolmount (50%, op.) • c.30 mmboe (169 Bscf) net reserves1 • Est. resources 200 Bcf – 1Tcf (gross) • Est. peak production 150-200 mmcfd

(gross) • 2017 investment decision, first gas

2019/2020 • Further discoveries and prospects

Babbage (47%, op.) • Adds gas production to Premier • 19 Bscf (3.2mmboe) net reserves1 • 2016 ytd production: 3.4 kboepd (net)

in line with 2015 • Plans to operate unmanned

Elgin Franklin Area (5.2% non-op.) • 34.6 mmboe net reserves1

• 2016 ytd production: 5.3 kboepd (net), 14% up on 2015

• Current production rates expected for next 3 years

• Development drilling through to 2019, 7 new wells, capex (net) £50m

• Low opex of $8/boe in 2016

Significant gas

discovery

Opportunity to reduce costs

and enhance production

World class asset with long-term production

In-field and near-field

growth opportunity

2016 YTD Production

Total 17.2

kboepd 1. as per effective date 1.1.2015

1. as per effective date 1.1.2015

Elgin-Franklin area

Huntington

Other CNS

Babbage area

Other SNS

May 2016 | P25

• Acquired with a valuable hedging portfolio in 2016 and 2017 – 2016: 32% estimated gas production @ 63p/therm, 33% estimated liquids production

@ $97/bbl – 2017: 21% estimated gas production @ 57p/therm

• Significant benefit to covenants (Net Debt to EBITDAX) at 30 June 2016 and 31 Dec 2016

• Expected payback of around 2 years, sooner if potential disposal of assets

• Sharing of liabilites with seller on Ravenspurn North & Johnston • c.£250m of historic tax paid off-settable against future decommissioning

expenditure

Quick pay back

• Adds significant cash flow in 2016 and 2017 even at current oil/gas prices – c.15mboepd of net production and associated cash flow added on completion – YTD production ahead of forecast

Strong cash flow

Valuable hedging portfolio

Covenant accretive

Financial benefits of the E.ON acquisition

Abandon- ment

liabilities mitigated

May 2016 | P26

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

May 2016