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North Sea and the GoM: Key Market DriversMay 2012
2
I. Introduction and Regional Economic Fundamentalsa) A slow US recovery Vs weakness in the Eurozoneb) Oil Price \forecast 2013
i. Brent/WTI spread
II. Key Market Driversa) Platformsb) Subsea Units (including Wells)c) Drilling activity
i. New Wells and Permitsii. E&A Indicators
d) Main Market Trendsi. Decline in shallow water activity
- Markets in Transitionii. Project Delays/Market Anxiety
III. Subsea Focus (North Sea in Context)a) Introduction – Subsea Market Evolutionb) Production Forecastc) Future Activity Indicators
Contents
Introduction – Oil Price Activity
SECTION I
4
Despite a currently weak state neither the US nor NWECS are likely to witness a dramatic downturn in oil demand
The Economic Fundamentals
Manufacturing PMI
Consumer Confidence
• US – Remains mildly supportive (A ‘recovery’ of sorts): ‐ A strong Q1 2013 compared to Q4 2012 (albeit below expectation)‐ New orders and production activity stayed high‐ Manufacturing PMI dropped slightly in April although it remains in
the ‘comfort’ rage of expansion
• Eurozone - Disaster avoided, manufacturing weakness continues:‐ GDP declined 0.6% in Q1 2013, following a 0.6% drop in Q4‐ 2013 outlook: further headwinds and waning economic growth‐ PMI stayed below 50 for 22 consecutive months: manufacturing
remains in a steep downturn
• China – Growth hit by lowering external demand and stagnant industrial production‐ GDP growth slowed to 7.8% in 2012 (11yr low)‐ Q1 2013: Economic activity remained weak (7.7% GDP growth rate)‐ Despite disappointing growth, China shows limited appetite for
further economic stimulus (Bejing set a 7.5% GDP target for 2013)
Jan/11 Apr/11 Jul/11 Oct/11 Jan/12 Apr/12 Jul/12 Oct/12 Jan/13 Apr/1335
40
45
50
55
60
65
US China EurozoneSources: US Manufacturing PMI (ISM); China Manufacturing PMI (National Bureau of Statistics of China); Eurozone Manufac-turing PMI (Markit)
Jan/11 Apr/11 Jul/11 Oct/11 Jan/12 Apr/12 Jul/12 Oct/12 Jan/13 Apr/1350
60
70
80
90
100
110
120
130
140
150
China US Eurozon 100MarkSources: Eurozone Economic Sentiment Indicator (European Commission); China Consumer Confidence (National Bureau of Stat-istics of China); Michigan Consumer Sentiment Index (Thomson Reuters/University of Michigan)
5
Oil Price Forecast 2013
Jan/12 Mar/12 May/12 Jul/12 Aug/12 Oct/12 Dec/120
20
40
60
80
100
120
140
BRENT WTI
$/bb
l
Sources: Infield Systems
Brent/WTI 2012 Rpice
A Tight Trading Range for Brent
Brent will likely be traded within a relative narrow range between $100 and $120/bbl
• Infield Systems forecasts that Brent prices will be traded within a $100-120 range in 2013
• Brent has traded within a narrow range during the last couple of years‐ This range was high enough to support supply, but not too high to
make considerably damage the global economic recovery
• Infield Systems believe that a $90/bbl floor would only be broken for short periods of time‐ Low prices are likely to spur supply responses from oil producing
countries‐ e.g Saudi Arabia could reduce supply in response to low prices to
balance the market. The country produced a 30-year high of 10.1mbpd in Jun/12, but has since reduced to 9.5mbpd
‐ In contrast, a period of sustained high prices exceeding $120/bbl is likely to be met with demand responses
‐ Ie. OECD countries could release their strategic petroleum reserves in the market
• In summary, without unexpected geopolitical tensions and supply outages, oil prices are likely to remain in the tight range in 2013
Jan/11 May/11 Aug/11 Nov/11 Feb/12 May/12 Aug/12 Nov/12 Feb/1360
70
80
90
100
110
120
130
140
150
160
BRENT
$/bb
l
Supply Responses
Demand Responses
Sources: Infield Systems
6
Brent/WTI 52-week Spread
OECD Europe Annual Oil Stock
US Commercial Crude Oil Stock
Brent and WTI SpreadA wide spread between Brent and WTI prices is likely to remain throughout 2013/14 before gradually narrowing to about $6/bbl in 2020
• Increasing pipeline capacity and rising rail shipments in recent months have helped shrink the oil-glut in Cushing and have brought the Brent/WTI spread down to about $10/bbl in April 2013 from $23/bbl in February. However, we anticipate that an average spread above $10/bbl is unlikely to narrow down in the near future‐ Brent is supported by a premium attached to the unstable
MENA supply and increased demand for Brent grades from countries in Asia like South Korea and China
‐ In contrast, WTI is supressed by high production from the Bakken oil shale formation, high stockpiles in Cushing and large-scale unconventional shale-oil development
Apr/12 Jun/12 Aug/12 Oct/12 Dec/12 Feb/13 Apr/130
5
10
15
20
25
30
Brent/WTI Spread
$/bb
l
Sources: Infield Systems
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec250
270
290
310
330
350
370
390
7 Year Range 7 Year Average 2013
mbb
ls
Sources: Infield; Total Stocks Database, U.S. Energy Information Administration
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 20121,150
1,200
1,250
1,300
1,350
1,400
1,450
mbb
ls
Sources: Bloomberg
7
Production Cost Curve
Average Field Sanction Point by Water Depth
Field Sanction Points by Water Depth
Field Sanction Points and Cost CurvesDespite market volatility, field investment has continued as sanction points remain relatively low
• Conventional fields are viable in all price scenarios ‐ Shallow water reserves clustered between $10-30/bbl‐ There are 1,927 shallow water fields worldwide
• Deepwater fields range between $36 and $80/bbl across regions and operator types‐ Ultra-deepwater fields extend out to a maximum of $100/bbl
with the majority sitting between $60 and $80/bbl‐ Heavy oil and shale oil requires oil prices in excess of $80/bbl
to be sanctioned‐ Arctic developments highly varied depending on conditions
• The current oil price is therefore sufficient so as to support the vast majority of developments
Alread
y Pro
duced
MENA Conven
tional
Other
Conventional
CO2 EOR
Other
EOR
Deep W
ater
Arctic
Heavy O
il Bitu
men
Oil Shale
s
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0
20
40
60
80
100
120
140
160
180
200
Available Quantity (Left) Cost Range (Right) Low Oil Price Medium Oil PriceHigh Oil Price
Avai
labl
e Q
uanti
ty (b
n ba
rrel
s)
$/b
arre
l
Sources: Infield; IEA Medium-Term Oil Market Report© OECD/International Energy Agency 2011, page 62 0 10 20 30 40 50 60 70 80 90 100 110
0
500
1,000
1,500
2,000
2,500
3,000
3,500
Sanction Price ($/bbl)
Wat
er d
epth
(m)
Shallow
Deep
Ultra Deep
Sources: Infield Systems
0-500 500-1000 1000-1500 1500-2000 2000-2500 2500-30000
50
100
150
200
250
300
15
25
35
45
55
65
75
1927
Number of projects Sanction PriceWater depth (m)
Sanc
tion
Pric
es ($
/bb
l)No.
of F
ield
s
Sources: Infield Systems
Key Market Drivers
SECTION II
GoM Platforms
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 20190
5
10
15
20
25
30
35
40
45
Fixed FloatingSources: Infield Systems
GoM Platform Installations by Type (Units)
GoM Platform Fabrication by Type (mT)
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 20190
50,000
100,000
150,000
200,000
250,000
Fixed FloatingSources: Infield Systems
Poor shallow water prospects replaced by growing confidence in deeper water plays
• Mature ultra shallow WD sector remains weak‐ Mature plays face tough competition from shale gas
(export LNG potential – Sabine Pass)‐ Poor prospects mean operators focus on new plays
• Floating sector sees largest proportion of new opportunities‐ Driven by Deepwater production growth‐ Significance of IOC investment
o Chevron: Big Foot / Jack St Maloo Shell: Olympus/Stones
• Importance of Independents (floaters)‐ Providing significant stimulus to GoM floating activity
from 2014o Hess: Tubular Bellso Hess Delta House (maintained visibility for
2016)o Anadarko: Heildelberg spar
• Delays‐ Mad Dog 2
NWECS Platforms
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 201905
101520253035404550
Fixed FloatingSources: Infield Systems
NWECS Platform Installations by Type (Units)
NWECS Platform Fabrication by Type (mT)
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 20190
50,000
100,000
150,000
200,000
250,000
300,000
350,000
Fixed FloatingSources: Infield Systems
Market in transition; the decline of shallow water activity and rise of floaters
• Fixed platforms remain a distinct driver in the North sea ‐ Current glut in large fixed installs phase rather than a
long term trend o UK: Clair Ridge, Mariner Ao Norway: Ekofisk, Eldfisk
‐ Independents lead new opportunitieso Nexen (Golden Eagle)o Premier Oil and Talisman (Montrose B)
‐ A market in slow decline
• Major opportunities in the near term reside in floating developments‐ From a tonnage perspective market currently in parity;
transition post 2014‐ Demand centered on IOCs but also independents
o Shell Fram FPSOo BP Quad 204 FPSOo DEO Perth FPSOo BG Group Knarr FPSO
11
Subsea Installations
GoM Subsea Installations by Type (Units)
NWECS Subsea Installations by Type (Units)
A key field development component for deepwater projects
• Subsea in the GoM remain positive‐ Super majors and independents investing heavily to bring
production on stream (Murphy - Dalmation)‐ Shell, Exxon and CVX strong – BP stabilising
• Project delays (e.g Mad Dog 2/Tiber)
• Europe to remain a key subsea space (However)‐ Angola is forecast to see subsea demand over take that
of Norway by 2018
• Operators keen to support subsea systems (BP/Statoil)
• Statoil’s drive in subsea production to impact significantly on overall production targets‐ Oil field recovery on mature assets
• BP expected to heavily support Norwegian near term market demand (Idun/Skav developments)
• UK Subsea demand to increase and keep pace with new opportunities in Norway (BP West of Shetland – Shiehallion)
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 201902468
101214161820
0102030405060708090100
Manifold Plem Plet Subsea Separation Template Wells (RHS)
Sources: Infield Systems
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 20190
10
20
30
40
50
60
0
20
40
60
80
100
120
140
160
Manifold Template Plem Subsea Compression Subsea SeparationWells (RHS)
Sources: Infield Systems
12
Drilling Activity - GoM
19701972
19741976
19781980
19821984
19861988
19901992
19941996
19982000
20022004
20062008
20102012
0
100
200
300
400
500
600
E&A Wells Platform installationsSources: BOEM Databank, Leasing Information & Exploration and Development Plans (March 2013)
Shallow water E&A and Platform Installs (GoM)
Deepwater Drilling Permits (GoM)
Q1 08Q2 08
Q3 08Q4 08
Q1 09Q2 09
Q3 09Q4 09
Q1 10Q2 10
Q3 10Q4 10
Q1 11Q2 11
Q3 11Q4 11
Q1 12Q2 12
Q3 12Q4 12
0
5
10
15
20
25
30
35
40
No. of Deepwater Drilling Permits (New Wells)Sources: BOEM Databank, Leasing Information & Exploration and Development Plans (March 2013)
GoM drilling outlook remains positive albeit heavily shored up by deepwater activity
• Production Levels
• Current contracted drilling fleet (as of March 2013)‐ 43 drillships, 81 Semisubs, 80 Jackups
• Mainly driven by deepwater activity, the drillship market shows particular strength.‐ Contracted drillships increased 140% from Jan’10 levels‐ Emerging lower tertiary plays
o X2 recent landmark discoveries
• Jack up market has comparatively performed modestly‐ Long term shallow water decline‐ Low gas prices‐ Competition from onshore investment
• Drilling data (2012):‐ 150 drilling permits for new wells (138; 2011)(114; post
Macondo)‐ 83 Deepwater drilling permits (highest since 2007)‐ New drilling assets (x2 new contract Q1 2013)
13
Drilling Activity - NWECS
UK Wells – Development vs Exploration (units)
Norway Wells – Development vs Exploration (units)
The maturity of the UK North Sea is in stark contrast to recent success in Norway
Source(s): ¹Norway’s Petroleum Agency
• Production levels (85.5bn boe recoverable reserves)¹
• Following three consecutive years of decline, the UK posted an increase in E&A activity in 2012‐ Levels remain far below pre-recession activity
• Compared to Norway, UK exploration success is limited‐ Only 2 discoveries in 2012
• Whilst much of the N.Sea is mature, WofS remains a continued success (indicative of future development)‐ BPs Claire field (recent US$500m increase in appraisals)
• The 3rd phase development of Claire may be the driver behind the Atlantic overtaking the N.Sea as the UK’s most productive oil region
• Norwegian E&A activity continues at pace compared to the UK sector‐ Regulatory changes‐ Potential in Barent Sea (undiscovered resources
upgraded to 8 bn bbl)
19701972
19741976
19781980
19821984
19861988
19901992
19941996
19982000
20022004
20062008
20102012
0
50
100
150
200
250
300
350
Development ExplorationSources: DECC
19701972
19741976
19781980
19821984
19861988
19901992
19941996
19982000
20022004
20062008
20102012
0
50
100
150
200
250
Development ExplorationSources: NPD
14
Historical exploration in Norway & the UKRelatively lower density of exploration wells in Norway is indicative of further activity (NCS), though the average size of discoveries would be expected to decline
• Exploration well activity in the UK sector of the Northern North Sea has been relatively centralised, with a cluster of wells drilled in a small area. In Norway, there is a lower density of drilling, with only 9 wells per 1,000km2, as opposed to 25 wells per 1,000km2 in the UK‐ With the regions sharing general
characteristics this indicates that there is a considerable level of exploration drilling yet to be conducted on the NCS
• Outside of the condensed Northern North Sea in both the UK and Norway there are several areas which are yet to be fully explored, specifically Northern Norway and the West of Shetlands‐ In order to maintain production levels,
and offset depletion from existing fields it is expected that both sectors will see a considerable increase in drilling activity over the coming period
‐ In the long term an increase in deeper water drilling, and harsh environmental conditions is likely to characterise drilling in the region
Exploration Well Density in the Northern North Sea
High exploration drilling density in the UK: 25 wells
per 1,000km2
Lower exploration drilling density in
Norway: 9 wells per 1,000km2
Sources: Infield Systems
15
Main Market Trends
GoM• Dramatic decline in Shallow WD demand
‐ Glut in onshore gas: potential for the US to be a LNG exporter
• Deepwater strength‐ Landmark discoveries in Walker Ridge area‐ Drilling permits trend upwards to finish highest since 2007‐ New discoveries ‘de-risk’ the region compared to Alaska plays
• Strong Offshore leasing‐ The first central GoM auction since Deep-water Horizon drew
US$1.7bn, the 4th largest for the region
• Potential delays‐ Mad Dog 2
Oil Price and Operator sentiment is indicative of a continued long run growth trend in deepwater GoM
North Sea• A market in transition
‐ Fixed platforms continue to drive unit installs; tonnage dynamics suggest a move towards more complex floaters
‐ Barents Sea/ West of Shetland
• Significant split in fortunes between UK and Norway activity‐ Concerns about UK reserves and dwindling production
(plummeted 19% in 2011 from 2010 levels)‐ Aging UK infrastructure : delays/shut ins likely‐ Norway has seen many high profile recent discoveries (Johan
Sverdrup and Skrugard & Havis)
• Subsea production is expected to make a major impact on production targets‐ UK expected to keep pace with anticipated new demand in
Norway (Statoil: Trol/Oseberg Delta – 2013/14) (BP: Schiehallion - long term support)(Maersk: Blue sky/Gryphon – near term)(Eon and Centrica - 2013)
Subsea Focus (North Sea in Context)
SECTION III
17
Subsea Boosting Projects by Water Depth Subsea Gas Compression by Water Depth and Tieback Distance
Subsea Market EvolutionSubsea boosting and compression to increase in prominence, particularly across the North Sea
• Seabed Oil Boosting – Drivers‐ Heavy oil‐ ↑ Tieback distance‐ ↑ Water depth‐ ↓ Reservoir pressure & temperature
• Seabed Oil Boosting – Key Players‐ Framo and Centrelift‐ Shell, Statoil and Petrobras
• Seabed Gas Compression – Drivers‐ Remote offshore gas fields‐ ↑ Tieback distance‐ ↑ Water depth‐ ↓ Reservoir pressure & temperature‐ Harsh metocean conditions
• Seabed Gas Compression – Key Players‐ Aker Solutions and Framo‐ Statoil, Total and Chevron
2014 2015 2016 2017 2018 2019 2020 2021 20220
200
400
600
800
1,000
1,200
1,400
1,600
AsgardGullfaks South
Troll Olje Snohvit
Laggan
Ormen Lange
Gorgon Central
Liwan
Jansz
Tieback distanceOnstream Year
Wat
er D
epth
Sources: Infield Systems
19941998
20002003
20052005
20072007
20082009
20102011
20122014
0
500
1,000
1,500
2,000
2,500
3,000
Marlim
Jubarte
MC King
Perdido HostWR Cascade
Wat
er D
epth
Sources: Infield Systems
18
Subsea Separation Units by Country Subsea Separation by Water Depth and EPIC Cost
Subsea Market EvolutionSubsea separation units separate oil, gas and water directly at the seabed level vs. the topside facility
• Subsea Separation Drivers at Mature Fields‐ Heavy oil‐ ↑ water production‐ ↑ tieback distance‐ ↑ water depth‐ ↑ number of subsea tiebacks
• Subsea Separation Drivers at Green Fields‐ ↑ gas volume fraction‐ ↑ tieback distance‐ ↑ water depth‐ ↓ reservoir pressure and temperature
• Subsea separation is now used across the likes of Norway, Angola, Brazil and the USA with units expected to be installed in each key region over the coming decade
• With production moving towards subsea at a rapid pace Infield expect heightened activity in the sector, particularly in deeper waters
Angola22%
Brazil28%Norway
17%
UK6%
USA28%
Sources: Infield Systems
1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 20180
500
1,000
1,500
2,000
2,500
3,000
Zinia
CorvinaCongro
Argonauta O
Marlim
Parque das Conchas
Froy SubsisTordis SubseaTroll S
Foinaven
Alaminos Canyon 857
Onstream Year
Wat
er D
epth
Sources: Infield Systems
19
North Sea Production Forecasts
UK Production Forecast (Mtoe/year)
Norwegian Production Forecast (Million scm eq.)
North Sea production expected to decline though new developments will ensure steady flow of work
• North sea in a state of general decline (peak 1990s)
• UK gas production, decreasing: Norway increasing
• Norwegian production: 226 million scm eq. - forecast to reduce to around 158 million scm eq. by 2030‐ Despite such decline opportunities exist ‐ Prospective discovery's will somewhat offset depletion‐ Barents Sea resources upgraded by 31% (8bn boe)¹
• UK production is in steep decline ‐ Now a net importer of crude and gas‐ To offset depletion UK to carry out drilling campaigns in
the more remote locationso WoS and Northern UK North Sea
20002002
20042006
20082010
20122014
20162018
20202022
20242026
20282030
0
50
100
150
200
250
300
Undiscovered resources Resources in discoveries Resources in fieldReserves HistoricSources: NPD
20002002
20042006
20082010
20122014
20162018
20202022
20242026
20282030
0
50
100
150
200
250
Oil (crude oil & NGLs) Natural Gas (net)Sources: DECC
million square metres of oil equivalent (million scm eq.)¹Norway’s Petroleum Agency
20
0 200 400 600 800 1000 12000
5,000
10,000
15,000
20,000
West of SheltandSouthern Gas BasinCentral North SeaNorthern North Sea
Exploration well sequence number
Reco
vera
ble
rese
rves
(bill
ion
boe)
Sources: DECC
Creaming Curves for Areas of the UKCS
UK Field Development Approvals
2008 2009 2010 2011 20120
2
4
6
8
10
12
New IncrementalSources: DECC
Norway vs. UKCS Creaming Curve
North Sea - Future Activity IndicatorsRecent activity limited (economic climate) - Long term prospects likely within more remote locations
Wells Drilled vs. Players and Oil Price
Buzzard
Foinaven, Schiehallion
Harding
Brent, Frigg, Beryl & Others
Claire
South Morcambe
MillerScott
Alba
Nelson
0 500 1,000 1,500 2,000 2,500 3,0000
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
UK
Norway
Exploration Wells
MM
BLE
Sources: INPD, DECC
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 20120
10
20
30
40
50
60
70
0
20
40
60
80
100
120
140
Oil price Wells Players
Wel
ls/c
ompa
nies
USD
/bar
rel
Sources: DECC
Administration
SECTION IV
22
Key ContactsInfield is a globally recognised oil & gas consultancy with a dedicated international team of cross-sector specialists
Contacts
34 Energy Professionals covering all geographic regions
Office Locations
LondonAberdeen
Houston
Singapore
Head Office
Regional Office
JV/Representative Office
Alexandre Gater Analyst
[email protected] +44 207 423 5039
23
Disclaimer
The information contained in this document is believed to be accurate, but no representation or warranty, express or implied, is made by Infield Systems Limited as to the completeness, accuracy or fairness of any information contained in it, and we do not accept any responsibility in relation to such information whether fact, opinion or conclusion that the reader may draw. The views expressed are those of the individual contributors and do not represent those of the publishers.
Some of the statements contained in this document are forward-looking statements. Forward looking statements include, but are not limited to, statements concerning estimates of recoverable hydrocarbons, expected hydrocarbon prices, expected costs, numbers of development units, statements relating to the continued advancement of the industry’s projects and other statements which are not historical facts. When used in this document, and in other published information of the Company, the words such as "could," "forecast”, “estimate," "expect," "intend," "may," "potential," "should," and similar expressions are forward-looking statements.
Although the Company believes that its expectations reflected in the forward-looking statements are reasonable, such statements involve risk and uncertainties and no assurance can be given that actual results will be consistent with these forward-looking statements. Various factors could cause actual results to differ from these forward-looking statements, including the potential for the industry’s projects to experience technical or mechanical problems or changes in financial decisions, geological conditions in the reservoir may not result in a commercial level of oil and gas production, changes in product prices and other risks not anticipated by the Company. Since forward-looking statements address future events and conditions, by their very nature, they involve inherent risks and uncertainties.
© Infield Systems Limited 2013
