2015 Half-Yearly Results
Transcript of 2015 Half-Yearly Results
2015 Half-Yearly Results 20 August 2015
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.
August 2015 | P1
Agenda
Introduction
UK
Sea Lion
Exploration
Finance
Outlook
Tony Durrant
Stuart Wheaton
Neil Hawkings
Robin Allan / Dean Griffin
Richard Rose
Tony Durrant
August 2015 | P2
2015 1H performance
Above budget and guidance year-to-date driven by 94% operating efficiency
Operating cash flow of $513 million
Production of 60.4 kboepd
Opex per barrel reduction
Net debt stable
Covenant flexibility
Solan and Catcher milestones achieved
Resource additions
Increased cash flows: strong production, lower costs and hedging benefits (which continue into 2H and 2016)
Many initiatives on-going; <$14/boe opex
Reduction in net debt to $2,093 million, despite investments in Solan and Catcher
Renegotiated terms; vote of confidence by banks and bondholders
On track for Q4 first oil from Solan and 2017 from Catcher
Discoveries at Zebedee and Isobel Deep; resource additions at Anoa
Refocusing the exploration portfolio Low cost acreage additions in Brazil and Mexico
August 2015 | P3
UK Stuart Wheaton
UK Business Unit Manager
UK – underlying growth
2015 1H
• Averaged 16.9 kboepd
• Improved operating efficiency
• Opex $29/bbl, down 17% (1H 2014: $35/bbl)
– Sale of high cost Scott area
– Active cost management and G&A cuts
• Sanctioned projects will see Premier’s UK production rise to c. 50 kboepd
• $3.3 bn of UK tax losses and allowances
Catcher
Balmoral Area Solan
Wytch Farm
Kyle Huntington
89% operating efficiency
Key projects Equity interest
First oil/gas
Operator Reserves YE14 (gross)
Balmoral Area c. 80% Various Premier 7 mmboe
Catcher 50% 2017 Premier 96 mmboe
Huntington 40% 2013 E.On 16 mmboe
Kyle 40% 2001 CNR 5 mmboe
Solan 100% 2015 Premier 44 mmboe
Wytch Farm 30% 1979 Perenco 47 mmboe
August 2015 | P5
Solan – long term vision
• Reserves upside potential
• Infill drilling opportunities; near field exploration
• Nearby accumulations; potential 3rd party business over Solan hub facility
• Consider farm down of equity post first oil
Cash generative
$26/bbl opex (LOF)
No tax
25,000
20,000
15,000
10,000
5,000
0 2020
Solan oil production rate (stb/d)
August 2015 | P6
Potential ullage?
Solan – 2015 1H highlights
• P1/ W1 tied in; P2 drilling
• Improved offshore productivity
• Removed partner funding concerns
• Reduced balance sheet exposure
• Cash spend to end July $1.65 billion
On track for Q4 first oil
August 2015 | P7
Solan – facilities update
2015 1H Sep - Oct Nov - Dec
Siem Spearfish 60 men; 180-280 hrs/day
Regalia flotel 135-150 men; 600-800 hrs/day
Superior flotel 200-220 men; 1,000 hrs/day
Habitation 20 men; 100-120 hrs/day
Complete construction works; commissioning of
accommodation
Commissioning of safety, accommodation, & production systems,
power generation & utilities
Tanker Offloading trials
Jul - Aug
Bibby DSV SOST &
P1/W1 tied in Ocean Valiant
P2 spudded
Victory 250 men; 800-1,000 hrs/day
Completion of over-side work & commissioning of
emergency power systems
Bibby DSV Complete commissioning of subsea infrastructure
o
Ocean Valiant W2 to spud
Commissioning of production systems
Commissioning of production systems
First oil
56,000 direct hrs to first oil
August 2015 | P8
Solan – drilling and subsea
P1 and W1
• Completed and tied-in
• P1 encountered 1,855 feet of sands
• 10-15 kbopd
• First oil Q4 2015
P2 and W2
• P2 nearing completion
• 3,000 feet of sands targeted
• W2 to spud in September
Field
• Ramp up to 25 kbopd once both producer/injector pairs on-stream
Subsea
• Tank tied in
• Commissioning to complete in September
Top Solan sand depth map
P2 cross-section
250m
500m Pressure
data suggests good
connectivity
W1
P1
W2
P2
Solan seal
Current bit position Solan pay sands
P2 on prognosis
August 2015 | P9
August 2015| P10
Catcher area
Reservoir upside
Near field tie-backs
Exploration upside
No tax
Catcher 5P, 2I
Varadero 4P, 3I
Burgman 5P, 3I
Catcher execution phase progressing
August 2015 | P11
• 96 mmboe (50 per cent, operator)
• $1.6 bn (gross budget to first oil)
• Post ramp up, peak production of c. 50 kbopd
Carnaby discovery
Formal concept select
Burgman and Varadero
discoveries
Acquired acreage as part of Oilexco
Catcher discovery
FPSO and SURF HUC
DECC approval Increased interest to 50% following
EnCore acquisition
2009-2011 2012 2013 2016 2015 2014 2017 2018
Near field exploration
First oil
FPSO and SURF fabrication
commenced
SURF installation
Development drilling
Catcher – FPSO
1H Highlights
• Turret and mooring system progressing
– Mating cone module fabricated and delivered
• Hull fabrication on-going in Japan and Korea
• Topsides fabrication underway in ProFab, Dynamac and Asia Offshore yards
August 2015 | P12
Catcher – subsea
• 2 templates installed (Catcher 1 & Burgman 1)
• PLEM installed • 60 km gas export
pipeline lay completed • Fabrication of remaining
templates completed • Fabrication of towheads
well-advanced • First steel cut on mid-
water arches • Fabrication of bundles to
start in H2 • Fabrication of risers and
jumpers to commence in 2016
August 2015 | P13
Catcher – drilling
September 2014 | P14
CCI2
CCP3
CTP1
CTI1
Template 1
1H Highlights
• Ensco 100 rig on hire since July
• Pilot hole completed
• Batch drilling of 30” & 20” sections of first 4 wells completed
• Operations on schedule and within budget
– Drilling ahead at CTI1
22 wells (14P, 8WI)
Six 4-slot templates
2 phases of drilling on each field
August 2015 | P14
Catcher – CTI1 progress
• Operations on schedule and budget
• Reservoir on prognosis; ‘injectite wing’ and main reservoir found within 7 feet of pre-drill forecast
• Setting production casing and will drill ahead reservoir section seeking ~250 feet net pay in ~600 feet gross interval
Catcher Discovery wells
Tay reservoir
Cromarty reservoir
August 2015 | P15
1.5km to nearest offset well Reservoir encountered on depth
CTI1
Sea Lion Neil Hawkings
SE Asia & Falkland Islands Director
De-risking the Sea Lion development
August 2015 | P17
• Phase 1a reservoir is fully appraised, subsurface plan is robust
• FPSO and SURF is well understood, conceptual design is now mature
• Key project execution contractors are to be selected ahead of FEED
• Financing plans progressing well
• Upside in the area has increased and become better defined
• Stakeholder discussions continuing
Exploration Robin Allan – N. Sea and Expl’n Director
Dean Griffin – Head of Exploration
Exploration – re-shaping the portfolio
Balance of wells targeting Mature verses Emerging plays
2012 2015
North Sea and SE Asia
Falklands, Brazil and Mexico 11 0
Growth in emerging basins
with material opportunities
Rationalisation in
mature areas
• Focusing on under-explored, emerging plays in proven hydrocarbon provinces
– Entry into Brazil and follow-on farm in to Block 661, Ceará Basin
– Successful entry into Mexico with award of Blocks 2 & 7
• Minimising up-front capex commitments
• Current industry conditions favour low cost acreage acquisition
• Exiting acreage in traditional, more mature areas (save for near-field exploration)
– Significant disposal proceeds and reduced well commitments
– Improved materiality of discoveries
• Net unrisked prospective resource of >1 bn boe
100% Emerging
100% Mature
2015 well campaign
2012 well campaign
17 51
August 2015 | P19
2015 North Falklands Basin campaign
2015 1H highlights
• Zebedee oil & gas discovery (36% op interest) – adds c. 50 mmbbls to Phase 2
• Isobel Deep oil discovery (36% op interest) – de-risks the Isobel/Elaine fan complex (un-
risked Pmean resource of 400 mmbbls) – opens up potential Phase 3 development
Two discoveries
from two wells
2015 2H look ahead
• Jayne East (36% op interest) – would add resource to Phase 2
• Chatham (40% op interest) – would add resource to Phase 1b
Beyond 2015
• Additional exploration/appraisal prospects identified for drilling in 2017/2018
Chatham Pmean
47 mmbbls
50 mmbls
Zebedee
Southern exploration
leads
Phase 2 prospects
PL032 prospects
Jayne East Pmean
39 mmbbls
Aim • Demonstrate exploitation potential of F2 • Explore upside potential of F3
Isobel / Elaine
Pmean
400 mmbbls
August 2015 | P20
Jayne East and Isobel Deep
Full stack amplitude at F3G horizon • Jayne East targets northern end of F3 fan sequence and shallower F2 horizons
• Further drilling at Isobel / Elaine complex to confirm significant resource potential of southern F3 fan system (unrisked Pmean 400 mmbbls)
North Falkland Graben
Isobel / Elaine Re-drill Isobel Deep
Jayne East
Zebedee
Jayne East
Isobel Deep
Isobel / Elaine
August 2015 | P21
10Km
Brazil – high quality address
• Limited drilling in the deeper water parts of the northern Brazil basins
• Recent significant discoveries in the Ceará, Potiguar and Sergipe Basins
• Success of West African Transform Margin (WATM) not yet fully tested in Brazilian basin equivalents
• Regional play work to identify sweet spots within high graded basins with proven active petroleum systems
Source IHS/Petroview
WATM Basins Jubilee – 771 MMboe
Baobab – 356 MMboe Enyenra – 200 MMboe
Keta-Togo-Benin Basin Ojo oil discovery
Douala Basin
Rio Muni Basin Ceiba – 264 MMboe
Okume – 107 MMboe Offshore Potiguar Basin
Pitu discovery
Ceará Basin Pecem & 1-CES-161
Barreirinhas Basin 1-MAS-036 gas discovery?
Para-Maranhao Basin Harpia discovery?
Foz do Amazonas Basin
Pernambuco Paraíba Basin
Sergipe-Alagoas Basin Sergipe discoveries (x5)
795 MMboe total
August 2015 | P22
Brazil Ceará Basin – expanding acreage footprint
Pecem discovery • Flowed light oil
to surface when tested in 2014
• De-risks key play elements
Outline of new 3D survey being acquired 3Q15
Cretaceous sand channel systems
Brazil Focus Basin
• Strong analogies with West African Tano basin discoveries
• Proven light oil petroleum system
• Multiple play types
• Attracted supermajors to make significant operational commitments
Opportunity
• Dominant position in basin
• Low cost farm-in to 661
• 3 wells drilling late 2017/18
• Premier coordinating rig-share
Mean gross unrisked resource
> 2 bn bbls
August 2015 | P23
Mexico – low cost entry
Strong partnership
Proven but under-explored
hydrocarbon basin
Low cost entry
August 2015 | P24
Block 2 • Primary target – 100 mmbbls • 3 follow on prospects of c. 80-100 mmbbls each
Block 7 • Primary target – 130 mmbbls • 4 follow on prospects of
c. 40-150 mmbbls each
Block 2
Salt stock
Closure
Miocene Depth Structure Map – Poblano Prospect
Low cost entry to high quality acreage • Awarded 10% in Blocks 2 & 7,
shallow water Sureste Basin • Option to increase interest to
25% prior to drilling • Numerous leads in established
and emerging plays • Fully carried to first well on each
block
Finance Richard Rose
Finance Director
Strong cash flows in 2015 1H
6 months to 30 June
2015
6 months to 30 June
2014
Working Interest production (kboepd) 60.4 64.9
Entitlement production (kboepd) 55.7 59.7
Realised oil price (US$/bbl) - post hedge 83.7 107.9
Realised gas price (US$/mcf) - post hedge 7.2 9.1
$m $m
Cash flow from operations 570 609
Taxation (57) (110)
Operating cash flow 513 499
Capital expenditure (518) (506)
Disposals 83 -
Finance and other charges, net (49) (49)
Dividends - (44)
Share buy back - (33)
Net cash in (out) flow 29 (236)
Capital expenditure ($m) Comprises $49m from the Block A Aceh sale and ~$34m positive adjustment from Scott area disposal Liquids hedging
1H 2015 2H 2015 2016
Barrels hedged
2.7 m 2.85 m 3.5 m
Average price ($/bbl)
$103 $92 $69
2015 1H FY 2015 E
Exploration $115 $240
Development $403 $900
Total $518 $1,140
August 2015 | P26
Significantly reduced costs
August 2015 | P27
30% reduction in opex
• Sale of Scott area
• Renegotiation of contracts
• Operating efficiencies
• Lower insurance & fuel costs
• Reduced headcount
• Contractor rate cuts
0
500
1000
1500
2014 2015 2016 2017 2018 2019
Committed capex ($m) P&D Capex
Exploration
0
100
200
300
400
500
FY 2014 (actual) 2015 initialbudget (Oct 14)
2015 finalbudget (Feb 15)
2015 forecast(Aug 15)
Opex ($m)
0
50
100
150
200
250
300
350
FY 2014(actual)
2015 initialbudget(Oct 14)
2015 finalbudget(Feb 15)
2015forecast(Aug 15)
Gross G&A ($m)
2015 1H: $14/bbl opex
Significantly reduced
capex commitments
from 2016
Forecast
Actual
Forecast
Actual
6 months to 30 June 2015
$m
6 months to 30 June 2014
$m
Sales and other operating revenues 577 885
Cost of sales (684) (646)
Gross profit/(loss) (107) 239
Exploration/New Business (52) (50)
General and administration costs (8) (13)
Disposals - (84)
Operating profit/(loss) (167) 92
Financial items (48) (41)
Profit/(loss) before taxation (215) 51
Tax credit/(charge) (160) 122
Profit/(loss) after taxation (375) 173
Income statement
Operating costs ($/boe)
* excludes insurance receipts of $4.7m
Cost of sales breakdown
2015 1H 2014 1H
UK $28.8 $34.9
Indonesia $8.9 $10.1
Pakistan $3.2 $2.7
Vietnam $10.1* $15.5
Group $13.7 $18.5
Profit before tax and impairments 171 195
August 2015 | P28
0
250
500
750
Operatingcosts
Stockunderlift
Royalties DD&A Impair-ment
Cost ofsales
Non-cash items
$3.3 bn of UK tax losses and allowances
Liquidity and balance sheet position
At 30 June 2015
$m
At 31 Dec 2014
$m
Cash 372 292
Bank debt (1,482) (1,230)
Bonds (753) (955)
Convertibles1 (230) (229)
Net debt position (2,093) (2,122)
Covenant headroom $417 $700
Gearing2 59% 53%
Cash and undrawn facilities 1,446 1,940
1 Maturity value of US$245 million 2 Net debt/net debt plus equity
Average debt costs of 4.7% (fixed) and 2.2% (floating)
Net debt/ EBITDAX Old covenants Amended covenants
August 2015 | P29
307 362
1238
558
0
200
400
600
800
1000
1200
1400
2015 2016 2017 2018 2019 2020-2024
Drawn debt maturities ($m)
0
1
2
3
4
5
20151H
2015FY
20161H
2016FY
20171H
2017FY
Summary Tony Durrant
CEO
20 19
17
14 16
0
5
10
15
20
2013 2014 2015budget
2015 1H 2015forecast
Outlook
August 2015 | P31
0
500
1000
1500
2014 2015F 2016 2017 2018 2019
P&D Capex
Exploration
• Growing production profile
– Intense focus on execution
– Reducing level of spend
2.
• Robust, low cost production generates good cash flow
1.
• Free cash flow will be directed at debt reduction
3.
Illustrative capital allocation @ $60/bbl
P&D committed capex
Cash available for debt reduction
Exploration commitments
Committed capex $m
Opex ($/boe)
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
August 2015