2015 Annual Results 25 February 2016 Forward-looking statements - - PowerPoint PPT Presentation

2015 Annual Results

25 February 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.

February 2016 | P1

Introduction

Tony Durrant Chief Executive Officer

Sea Lion Phase 1 project scope modified with lower break-even oil price; draft FDP submitted and FEED contracts in place

2015 – delivering on our targets

57.6 kboepd, above guidance, driven by high operating efficiency and despite disposal of non-core assets

Strong production performance Reducing costs Focus on net debt Funding flexibility and liquidity Progressing Solan and Catcher Reserve and resource additions

$16/boe opex, down >$100m from 2014 Gross G&A costs c.$230 million, down >$75 million from 2014 Net debt c.$2.2 billion, modest increase reflecting corporate actions

• ffsetting ongoing investment in Solan and Catcher

Renegotiated covenant terms; $1.2 billion liquidity at year end; unsecured facility with no redeterminations Solan: final commissioning; first oil delayed by severe weather Catcher: first oil on track 2017, key milestones achieved, under budget 2P reserves increased by 89mmboe to 332mmboe Resource additions at Zebedee and Isobel Deep

Refocusing the portfolio

Asset disposals (Norway and Aceh, Indonesia) Value accretive E.ON asset acquisition agreed

February 2016 | P3

Progressing Sea Lion

Proposed E.ON acquisition – rationale and status

• 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

• Adds immediate cash generative production, tax synergies

and material covenant accretion with rapid payback – meeting Premier’s stated acquisition criteria

• Status of the acquisition:

– Good progress has been made with lending group consents – Shareholder circular expected to be issued in March – Completion expected in Q2

February 2016 | P4

Total 73 kboepd

Proforma 2015 Production ProformaYE15 Reserves

Total 375 mmboe

UK

Robin Allan North Sea and Exploration Director

Solan – first oil shortly, moving on to second oil

February 2016 | P6

First oil

• All construction and subsea infrastructure

fully commissioned

• Tanker trials complete and habitation

achieved (25 persons on the platform)

• Winter weather has impacted final

commissioning – platform access 1/3rd vs Winter 2014

• <10,000 hours remaining

Delivering second oil and ramp up to full production

• Test the facilities and planned shut down

ahead of second oil

• Utilise Superior Flotel to maximise

workforce on platform to complete remaining systems

• Complete W2 and tie in; recommence

production and ramp up

• Complete P2z and tie in by mid-year

Full production by Q3 20-25 kbopd

Catcher – under budget and scheduled for 2017

2015 Highlights

• 2015 subsea installation programme

successfully completed

• Fabrication of 2016 subsea equipment and

mooring system on schedule

• Hull fabrication on-going in Japan and Korea

– First section delivered in December

• Topsides and Turret fabrication underway in

ProFab, Dynamac and Asia Offshore yards

Key milestones for 2016

• 2016 subsea installation programme

– Remaining templates, bundles and riser system – Buoy and Mooring system (to be ready for FPSO in 2017)

• Commencement of hull and integration

work in Singapore from summer 2016

February 2016 | P7

Drill Centre Manifold Towhead

$1.6bn (gross budget to first oil) Under budget at 2015YE

FPSO: First section delivered in December Aerial View of Catcher Modules; Singapore E-House Completed

Opex $20/bbl at plateau production c.50 kbopd

• Ensco 100 rig on hire since July
• 3 wells drilled with excellent operational

performance

– two injectors (CTI1 and CCI2) – one producer (CCP3)

• 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

• 5 further development wells and an exploration

well planned for 2016

Catcher – initial drilling results encouraging

Well results confirm high quality reservoir

February 2016 | P8

Catcher CCP3 producer well Catcher exploration well 29-1 Cromarty reservoir

0 500ft

Huntington (38.5%, op.)

• Existing Premier field, equity

interest increases to 100%

• 2016 ytd production: 13 kboepd

(gross), in line with 2015

E.ON UK assets – strong start to 2016

February 2016 | P9

Tolmount (50%, op.)

• Resources 200 Bcf – 1Tcf (gross)
• Peak production 150-200 mmcfd

(gross)

• 2017 investment decision, first gas

2019/2020

• Further discoveries and prospects

Babbage (47%, op.)

• Current gas production
• Field outperformance
• Plans to operate unmanned

Elgin Franklin Area (5.2% non-op.)

• Current production > 110 kboepd

(gross)

• Current production rates expected

through to 2019

• Development drilling programme
• 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

• pportunity

2016 YTD Production

SE Asia & Falkland Islands

Neil Hawkings SE Asia & Falkland Islands Director

South East Asia – reliable low cost production

February 2016 | P11

Vietnam

• Strong 2015 production and operating efficiency

– 32 kboepd (gross) production

• Progressing further cost reductions
• Planning f0r future infill programme targeting

unswept areas and low risk new reservoirs – To increase production above 2015 levels

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

Operating costs c.$13/bbl Operating costs

• c. $8/bbl

North Falklands Basin – potential confirmed

February 2016 | P12

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

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 – low cost option for large future value

• Phase 1 project economics enhanced

– 220 mmbbl from NE & NW areas of PL032 – 18 wells (13 pre-drilled) and 20 year field life – $1.8bn 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

February 2016 | P13

Falling break-even price

Subsea Installation Subsea Prod’n System Risers FPSO

“Collaborative partnership” “Collective costs incentives”

Finance

Richard Rose Finance Director

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)

1H 2016 2H 2016 Barrels hedged (Kbbls) 1,890 2,530 Average price ($/bbl) 74.7 72.4 2015 2016E Exploration $216 c$100 Development $854 c$600 Total $1,070 c$700

February 2016 | P15

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

February 2016 | P16

200 300 400 500 FY 2014 (actual) 2015 Budget FY 2015 (actual) 2016 Budget Solan, Huntington

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

Cost reduction continuing

February 2016 | P17

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) 2015 Budget FY 2015 (actual) 2016 Budget

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
• perators
• 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 5-10% G&A down 10%

Covenant compliance and mitigating actions

February 2016 | P18

• E.ON UK asset acquisition materially

covenant accretive

4.

• Covenant position amended

– Net debt $2.2 billion – Headroom > $900m (y/end) – 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 558 200 400 600 800 1000 1200 1400 1600

Drawn debt maturities (US$mm)

• 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

February 2016 | P19

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

Summary

Tony Durrant Chief Executive Officer

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

February 2016 | P21

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) 2015 Budget FY 2015 (actual) 2016 Budget Solan, Huntington 100 200 300 400 FY 2014 (actual) 2015 Budget FY 2015 (actual) 2016 Budget

G&A ($mm) Opex ($mm)

Looking forward

February 2016 | P22

Proven Track Record in Acquisitions/Divestment

• 6 separate transactions since 2013, focused on

pre-development assets

• E.ON portfolio offers further opportunities for

asset disposal

• Added 65 mmboe through acquisition (pro forma E.ON)

at cost of <$2/bbl in 2015

Portfolio Management

Quality 2018 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
• 750 mmboe of reserves and

resources

Forward Position

379 120 100 200 300 400

Divestments Acquisitions

$mm

Operating Cash flow Capex & Abex Operating Cash flow Capex & Abex Operating Cash flow Capex & Abex

2017 2018 2019

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

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 February 2016