2015 Half-Yearly Results 20 August 2015 Forward looking statements - - PowerPoint PPT Presentation
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
August 2015 | P1
August 2015 | P2
Above budget and guidance year-to-date driven by 94%
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
2015 1H
$35/bbl) – Sale of high cost Scott area – Active cost management and G&A cuts
UK production rise to c. 50 kboepd
Catcher Balmoral Area Solan Wytch Farm Kyle Huntington 89%
efficiency
Key projects Equity interest First
Operator Reserves YE14 (gross) Balmoral Area
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
Cash generative $26/bbl opex (LOF) No tax
25,000 20,000 15,000 10,000 5,000 2020 Solan oil production rate (stb/d)
August 2015 | P6
Potential ullage?
On track for Q4 first oil
August 2015 | P7
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
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
W2 to spud Commissioning of production systems Commissioning of production systems
First oil
56,000 direct hrs to first oil August 2015 | P8
P1 and W1
P2 and W2
Field
producer/injector pairs on-stream Subsea
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
Reservoir upside Near field tie-backs Exploration upside No tax
Catcher 5P, 2I Varadero 4P, 3I Burgman 5P, 3I
August 2015 | P11
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
Near field exploration
First
FPSO and SURF fabrication commenced SURF installation Development drilling
1H Highlights
– Mating cone module fabricated and delivered
Dynamac and Asia Offshore yards
August 2015 | P12
(Catcher 1 & Burgman 1)
pipeline lay completed
templates completed
well-advanced
water arches
start in H2
jumpers to commence in 2016
August 2015 | P13
September 2014 | P14
CCI2 CCP3 CTP1 CTI1
Template 1
22 wells (14P, 8WI) Six 4-slot templates 2 phases of drilling
August 2015 | P14
main reservoir found within 7 feet of pre- drill forecast
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
August 2015 | P17
Balance of wells targeting Mature verses Emerging plays
North Sea and SE Asia Falklands, Brazil and Mexico
11
Growth in emerging basins with material
Rationalisation in mature areas
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
commitments
cost acreage acquisition
mature areas (save for near-field exploration) – Significant disposal proceeds and reduced well commitments – Improved materiality of discoveries
>1 bn boe
100% Emerging 100% Mature
2015 well campaign 2012 well campaign
17 51
August 2015 | P19
2015 1H highlights
– adds c. 50 mmbbls to Phase 2
– 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
– would add resource to Phase 2
– would add resource to Phase 1b Beyond 2015
identified for drilling in 2017/2018
Chatham
Pmean
47 mmbbls
mmbls
Zebedee
Southern exploration leads Phase 2 prospects PL032 prospects
Jayne East
Pmean
39 mmbbls
Aim
Isobel / Elaine
Pmean
400 mmbbls
August 2015 | P20
Full stack amplitude at F3G horizon
shallower F2 horizons
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
water parts of the northern Brazil basins
the Ceará, Potiguar and Sergipe Basins
Margin (WATM) not yet fully tested in Brazilian basin equivalents
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
Pecem discovery
to surface when tested in 2014
play elements Outline of new 3D survey being acquired 3Q15 Cretaceous sand channel systems
Brazil Focus Basin
African Tano basin discoveries
system
make significant operational commitments Opportunity
share
Mean gross unrisked resource > 2 bn bbls
August 2015 | P23
Strong partnership Proven but under-explored hydrocarbon basin Low cost entry
August 2015 | P24
Block 2
Block 7
Block 2
Salt stock
Closure
Miocene Depth Structure Map – Poblano Prospect
Low cost entry to high quality acreage
shallow water Sureste Basin
25% prior to drilling
and emerging plays
block
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 $m Cash flow from operations 570 609 Taxation (57) (110) Operating cash flow 513 499 Capital expenditure (518) (506) Disposals 83
(49) (49) Dividends
Share buy back
Net cash in (out) flow 29 (236) Capital expenditure ($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 $1,140
August 2015 | P26
August 2015 | P27
30% reduction in opex
500 1000 1500
2014 2015 2016 2017 2018 2019
Committed capex ($m)
P&D Capex Exploration
100 200 300 400 500
FY 2014 (actual) 2015 initial budget (Oct 14) 2015 final budget (Feb 15) 2015 forecast (Aug 15)
Opex ($m)
50 100 150 200 250 300 350
FY 2014 (actual) 2015 initial budget (Oct 14) 2015 final budget (Feb 15) 2015 forecast (Aug 15)
Gross G&A ($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 $m Sales and other operating revenues 577 885 Cost of sales (684) (646) Gross profit/(loss) (107) 239 Exploration/New Business (52) (50) General and administration costs (8) (13) Disposals
Operating profit/(loss) (167) 92 Financial items (48) (41) Profit/(loss) before taxation (215) 51 Tax credit/(charge) (160) 122 Profit/(loss) after taxation (375) 173
Operating costs ($/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
250 500 750
Operating costs Stock underlift Royalties DD&A Impair- ment Cost of sales Non-cash items
$3.3 bn of UK tax losses and allowances
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$245 million 2 Net debt/net debt plus equity
Average debt costs of 4.7% (fixed) and 2.2% (floating) Net debt/ EBITDAX
Old covenants Amended covenants
August 2015 | P29
307 362 1238 558 200 400 600 800 1000 1200 1400 2015 2016 2017 2018 2019 2020- 2024
Drawn debt maturities ($m)
1 2 3 4 5 2015 1H 2015 FY 2016 1H 2016 FY 2017 1H 2017 FY
20 19 17 14 16 5 10 15 20
2013 2014 2015 budget 2015 1H 2015 forecast
August 2015 | P31 500 1000 1500
2014 2015F 2016 2017 2018 2019 P&D Capex Exploration
Illustrative capital allocation @ $60/bbl
P&D committed capex Cash available for debt reduction Exploration commitments
Committed capex $m Opex ($/boe)