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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: [email protected]
www.premier-oil.com
May 2016