Oil service update – January 2016

Oil service update – January 2016
- Recovery is still off the horizon
Martin Huseby Karlsen (Offshore drillers)
+47 24 16 91 93 | [email protected]
Eirik Ronold Mathisen (Subsea and E&C)
+47 24 16 91 91 | [email protected]
Jon Masdal (Seismic)
+47 24 16 92 97 | [email protected]
Marius Knudssøn
+47 24 16 91 94 | [email protected]
1|
Oil Services – 2015 trends to continue
 Following the 22% drop in offshore-focused E&P spending in 2015, we forecast a 20% drop in 2016
 Cash overspending among the offshore-focused oil companies remains a concern
 Likely to result in a continued lack of contract opportunities for offshore oil services
Offshore spending trending lower
Cash overspending for Majors
250
160%
140%
200
120%
13%
100%
150
-40%
126%
142%
6%
142%
3%
31%
33%
106%
105%
LTM*
YTD**
24%
98%
18%
80%
25%
60%
100
89%
40%
55%
20%
50
Average 2000-2008
Average 2009-2014
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014 2015e 2016e
Capex/OCF
Dividend/OCF
Share buyback/OCF
Overspending
Source: DNB Markets
* and ** = as of Q3 2015
2|
Deepwater client base is set to shrink
 Strategic decisions among several oil companies to shift spending away from deepwater
 Cost deflation offshore is matched by cost reduction onshore
 High flexibility in US onshore business model is an advantage vs offshore
 Many small- and mid-cap oil companies are scaling back deepwater investments significantly:
 Reduced volumes  Lower utilization
 Marginal buyers of service capacity disappear
 Pricing shift even more in favour of the EPs
EP Spending shifting away from deepwater.
Number of oil companies with active UDW rigs
35
-40%
30
25
20
15
10
5
Source: DNB Markets, ODS Petrodata
3|
Q4-15
Q1-15
Q2-14
Q3-13
Q4-12
Q1-12
Q2-11
Q3-10
Q4-09
Q1-09
Q2-08
Q3-07
Q4-06
Q1-06
Q2-05
Q3-04
Q4-03
Q1-03
Q2-02
Q3-01
Q4-00
Q1-00
0
Costs for a generic deepwater field development is down ~25-30%
 We estimate than offshore field development costs are down ~25-29% from peak
 Oil price is down more than cost is down
 Similar cost deflation seen onshore US.
 Hence a deepwater project is:
- Worse off today on an IRR basis
- Relative attractiveness of offshore versus onshore has not improved
CAPEX split generic deepwater field development
Price deflation oil services
-
5%
20%
-10%
Drilling (rig)
30%
Drilling (other)
15%
-20%
15-20%
-30%
25-29%
Subsea - SPS
15%
Subsea - SURF
FPSO/platform
Engineering
10%
20%
-40%
-50%
-60%
-70%
65%
Drilling (rig)
Drilling (other) Subsea - SPS
Subsea SURF
FPSO/platform Engineering
Source: DNB Markets
4|
Field
development
Offshore oil production could be more resilient than capex cut indicates
 Offshore EP Spending may fall ~40% without large impact on activity level related to development
 Hence oil production offshore may prove more resilient than spending drop should indicate
 Fields already under development set to contribute with meaningful production in the years to come
 5+% decline rates offshore required for offshore production to be flat for the next years
Fields already under development to contribute with
production (mmbbl/day)*
A generic EP budget
100%
6.0
-40%
90%
80%
~40%
70%
60%
5.0
4.0
50%
40%
3.0
30%
20%
2.0
10%
0%
1.0
Peak CAPEX
Exploration CAPEX Development pricing
down 75%
down 25%
Exploration CAPEX
Development
complexity and
standarization down
10%
Development capex
Base layer
2016
2017
2016
2018
2017
2018
2019
2019
2020
2020
Source: DNB Markets, Companies, Rystad Energy
* Crude Oil, NGL and condensate
5|
Development spending has been rather resilient
 Despite of reduction in E&P spending, development activity has been rather resilient
 Number of UDW rigs doing development drilling is rising
 Jack-ups doing development drilling was just slightly down in 2015 YoY, and well above historical levels
 Exploration drilling and seismic activities hit significantly
 Majors on track to meet their production guidance for the first time in years
More deepwater rigs do Development drilling
90
Majors on track to meet production guidance
70%
1,950
80
60%
70
50%
60
40
30%
1,750
20%
1,700
# of rigs
1,800
10
10%
0%
Jan-00 Apr-02 Jul-04 Oct-06 Jan-09 Apr-11 Jul-13 Oct-15
Demand for development rigs (l.h)
Development share (r.h)
3.5%
1,850
50
20
4.0%
1,900
40%
30
4.5%
3.0%
2.5%
2.0%
1.5%
1.0%
0.5%
1,650
-
Total (mmboe)
Growth (YTD)
Source: DNB Markets, ODS Petrodata
6|
Oil services need higher oil price… or more spending cuts
 For oil services to recover, oil companies need to start spend more money and cash-flow neutrality is the key
 Offshore-focused oil companies need a Brent oil price of ~USD65/bbl to balance operational cash in 2016e
 Alternatively, in a 50 dollar oil scenario, 2016 capex needs to fall 45% YoY for the oil companies to become cash flow neutral
 Risk that oil companies will focus on deleverage before boosting spending again
…or more spending cuts are needed
Higher oil price needed to E&P budgets to balance
67
65
65
64
64
64
63
63
62
implied 2016 capex growth
66
66
Needed oil price
-41%
66
-40%
-42%
-43%
-44%
-45%
-44%
-45%
-46%
-46%
-47%
-47%
-48%
-48%
-49%
61
-50%
2.8%*
-2.0%
-1.0%
0.0%
2016 production growth
1.0%
2.0%
2.8%*
-49%
-2.0%
-1.0%
0.0%
1.0%
2.0%
2016 production growth
Source: DNB Markets
7|
Oil service profitability is squeezed from all sides
Source: DNB Markets
8|
Overcapacity set to offset potential activity increases
 Offshore oil services is massively oversupplied
 Scrapping so far has been far from sufficient to compensate for collapse in demand
 Overcapacity situation could cap pricing improvements when activity eventually picks up
Offshore spending versus fleet growth
30%
Over building
Absorption
Balance
Over building
20%
10%
-10%
-20%
-30%
-40%
-50%
2008
Offshore E&P Spending
2009
Seismic
2010
2011
Offshore supply (PSV and AHTS)
2012
2013
Subsea heavy construction
2014
Subsea light construction
2015
2016e
Deepwater offshore rigs
2017e*
Jack-ups rigs
Source: DNB Markets, Companies
9|
CAPITAL MARKET OPPORTUNITIES
Limited ECM primary activity, and despite oil service equities down significantly
LTM, it is still to early to get excited on valuation and fundamentals
Development in key equity indices (LTM)
Segment performance (LTM and 3M change)
Equity market indices
140
130
120
100
-43%
-9%
S&P 500
-8%
-13%
OSEBX
Rig
-16%
-54%
-42%
90
-9%
-13%
80
70
-34%
60
Equity segment-indices
Index points
110
-43%
Brent (ICE)
-36%
OSV
-20%
-37%
Seismic
-32%
-5%
FPSO
-17%
-43%
50
-31%
Subsea
Feb Mar
Apr
S&P 500
May
Jun
OSEBX
Jul
Aug
Sep
Oil service1
Oct
Nov
Dec
-35%
Jan
Brent (ICE)
-60%
-50%
-40%
-30%
LTM change
-20%
-10%
3M change
1 Offshore
index consists of listed companies within the rig, OSV, seismic, FPSO and subsea segments.
Source: DNB Markets, FactSet
10 |
0%
CAPITAL MARKET OPPORTUNITIES
Limited primary DCM activity and bonds are starting to trade closer to recovery
levels
Development in key market indices (LTM)
Indices and sub-indices performance (LTM and 3M change)
High yield indices
140
130
120
Norway HY1
-8 %
-5 %
-8 %
USD HY (iBoxx)
-7 %
-2 %
EUR HY (iBoxx)
-3 %
-9 %
100
E&P
-2%
-8%
-8%
90
-18%
80
70
-9 %
High yield sub-indices
Index points
110
Oil service
-8 %
-6 %
1%
Shipping
1%
0%
Seafood
1%
60
-43%
0
-9 % -8 % -7 % -6 % -5 % -4 % -3 % -2 % -1 % 0 % 1 % 2 %
Mar-15
May-15
Jul-15
Sep-15
Norway HY1
EUR HY (iBoxx)
USD HY (iBoxx)
Oil service (Norway)
Nov-15
Jan-16
Brent (ICE)
LTM change
3m change
1
DNB High Yield (DNB Hedged)
Source: DNB Markets Credit Research, Bloomberg
11 |
But be aware of oil price correlation
 We believe shareprice volatility will be high due to the strong correlation with oil price
 2015 saw three meaningful bear market rallies (January–February, April–May, and October–November)
 We would not be surprised to see the same trend this year
Long-term oil price correlation
Oil price corelation in 2015 and YTD
600
120
-40%
110
500
100
400
90
80
300
70
200
60
100
Jan.05
50
Jan.06
Jan.07
Jan.08
Jan.09
Oil price
Jan.10
Jan.11
Jan.12
Oil Service index
Jan.13
Jan.14
Jan.15
Jan.16
Oil price
Oil Service index
Source: DNB Markets
12 |
CAPITAL MARKET OPPORTUNITIES
Significant uncertainty related to offshore going forward
 Oil market entered the harvesting phase, after the break neck pace of oil investments the past 5-10 years
 Offshore is loosing the capital allocation battle with US onshore
Where are we today?
 Offshore projects are being delayed and cancelled, and contract terms are being renegotiated
 Significant order books in most oil service segments
 Limited capital markets activity, and primarily on a «must raise» basis
 Industry planned for continued high growth at an oil price of USD 100-115/brl
 US onshore production boom (surprise)
How did we get here?
 Failed expectations from Petrobras and other deepwater developments
 Development costs running out of control
 Over-engineering, with expensive assets failing to provide acceptable returns
 Expect stabilisation / limited recovery in oil price - more L than U-shaped
What next?
 Cooperation and size will be crucial, resulting in consolidations and alliances, both vertically and horizontally
 Unsustainable capital structure in many service companies will result in increased restructuring activity
 The need for production growth outside US onshore and Middle East will be a catalyst for improved offshore markets
Source: DNB Markets, The Economist
13 |
CAPITAL MARKET OPPORTUNITIES
Restructuring likely to take place through several steps
Round 1




Cost cutting
Amortization holiday on bank debt
Easing/waiving of covenants
New equity
Round 2




Deferred instalments on bank debt
PIK of bond interest payments
Extension of bond maturities
Sale of assets and sale leasebacks
Round 3
 Conversion of debt to equity
 Debt restructuring
 New liquidity
14 |
Agenda
E&P spending – Recovery is still off the horizon
Drilling sector
Subsea sector
Seismic sector
Offshore supply
Appendix
15 |
Day-rates collapsing
 UDW rates currently around USD 200k level for both long-term and short-term jobs
 Contracting activity remains slow
 Record high number of UDW rigs available next 12 months
All-time high availbility
Ultra-deepwater dayrates (3 months average)
160
700
140
Number of UDW rigs
USDk/day (3m avg)
600
500
400
300
120
100
80
60
40
200
20
100
0
Jan-01
0
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Jan-03
Jan-05
Jan-07
Jan-09
Jan-11
Jan-13
Jan-15
With no new contracts
Historical
Source: DNB Markets research and ODS Petrodata
16 |
Oversupplied for the foreseeable future
 Our bottom-up supply demand model suggest a oversupplied market over the next years
 Developments taking longer than expected
 Near-term supply boosted by sublets
Oversupplied over the next years
Implied utilization
100%
250
90%
200
80%
70%
150
60%
100
50%
50
40%
Jan 00
Jan 02
Jan 04
Jan 06
Jan 08
Development
Exploration
Total Incremental demand
Supply
Jan 10
Jan 12
Jan 14
Jan 16
Options not exercised
Jan 18
30%
Jan.00
Jan.02
Jan.04
Jan.06
Jan.08
Implied UDW utilisation
Jan.10
Jan.12
Jan.14
Annual average 2016-2018e
Source: DNB Markets research and ODS Petrodata
17 |
Jan.16
Jan.18
Mostly easy scrapping so far
 Many of the scrapped rigs had been cold stacked for some time, hence having limited effect on the active supply
 Only 3 UDW rigs are retired so far, none of which has been “state of the art”
 The pace has slowed down significantly as rig owners learn how to stacking more cheaply
Chart on what scrapped floaters used to do
Scrapping activity has slowed down
40
25
20
30
15
20
10
10
5
0
0
2010
2011
2012
Scrapped
2013
Cold stacked
2014
Active
2015
2013 Q3 2013 Q4 2014 Q1 2014 Q2 2014 Q3 2014 Q4 2015 Q1 2015 Q2 2015 Q3 2015 Q4
Floater
Jackup
Source: DNB Markets research and ODS Petrodata
18 |
Downside on 2Y EV/EBITDA
 Consensus 2Y forward EV/EBITDA trades above historical averages
 On our numbers the sector trades at 2Y forward EV/EBITDA of 8.2x
 Modernization of fleets could justify slight premium to historical valuation
2Y forward EV/EBITDA
2Y forward EV/EBITDA by company (DNB estimates)
9.0x
14.0x
8.0x
12.0x
7.0x
10.0x
6.0x
5.0x
8.0x
4.0x
6.0x
3.0x
4.0x
2.0x
2.0x
1.0x
0.0x
Aug-06
Sep-07
Oct-08
EV/EBITDA (7.2x)
Nov-09
Dec-10
Jan-12
Average (5.6x)
Feb-13
Mar-14
Apr-15
Current DNBe (8.2x)
ATW
SDRL
RIG
FOE
Average
DO
Current
RDC
NE
19 |
ESV
Capital structure
 Songa Offshore, Ocean Rig, Pacific Drilling and Fred Olsen Energy with market cap being lowest portion of the EV
 Seadrill is the large cap with the most challenging position
 High leverage ratio across the space in 2017
Capital structure YE 2015 (EV breakdown)
Historical Net Debt to EBITDA
7.6x
8.0x
100%
7.0x
90%
6.0x
80%
6.0x
70%
4.6x
5.0x
60%
50%
4.0x
40%
3.5x
3.4x
3.0x
3.0x
30%
2.0x
20%
10%
1.0x
2.0x
2.0x
1.0x
0.8x
1.0x1.0x
3.3x
2.8x 3.0x
2.9x 2.9x 2.6x
3.0x
2.4x 2.3x
1.9x
1.9x
1.9x
1.9x
1.4x
1.3x
1.0x
0.8x
0%
DO
RDC
ESV
M cap
NE
RIG
Net debt
ATW
FOE
SDRL SONG PACD ORIG
Remaining capex
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
AWDR
20 |
Agenda
E&P spending – Recovery is still off the horizon
Drilling sector
Subsea sector
Seismic sector
Offshore supply
Appendix
21 |
Subsea sector – Lesser of two evils, but still evil
 Sanctioning of subsea wells fell to 10-year low in 2015, no improvement in sight
 Structurally lower subsea spending: 2017 subsea spending expected to be ~40% below 2014
 Investor perseption set to worsen in 2016 (earnings erosion and no improvement in order intake)
 Deepwater losing capital allocation is a major concern
Sanctioning of subsea wells (ex. Petrobras)
350
Subsea spending (2014 = 100)
120
300
-40%
100
250
80
200
150
60
100
40
50
20
2014 = 100
# of subsea wells sanctioned (excluding PBR)
2017e = 61
Greenfield
Brownfield
Source: DNB Markets
22 |
Subsea backlogs are down ~40% from mid-2014, no rebound in sight
 We expect order backlog momentum to remain depressed in 2016
 Set to result in an air pocket in terms of installation activity in 2017-2018
 Can we trust the order backlog now being built?
SURF order backlog (USDm)
Book to bill SURF companies
45,000
1.6x
40,000
35,000
1.4x
30,000
1.2x
25,000
1.0x
20,000
0.8x
15,000
0.6x
10,000
0.4x
-
0.2x
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
5,000
2006
2007
2008
2009
Technip
2010
Subsea 7
2011
Saipem
2012
2013
2014
2015
0.0x
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015e
Average book to bill SURF
Source: DNB Markets, Companies
23 |
2016e
Earnings erosion set to accelerate in 2016 and continue into 2018
 We forecast significant earnings erosion in 2016 due to:
- Higher priced backlog rolls over
- Lower utilization
- «One-off» restructuring costs
SURF revenue growth versus offshore capex
Margin trend (EBIT) SURF companies
40%
18.0%
16.0%
30%
14.0%
20%
12.0%
10%
10.0%
-
8.0%
6.0%
-10%
4.0%
-20%
2.0%
-30%
2007
2008
2009
2010
2011
Revenue growth
2012
2013
2014e
2015e
Offshore E&P spending growth
2016e
2017e
2018e
2006
2007
2008
2009
2010
2011
2012
2013
2014 2015e 2016e 2017e 2018e
EBIT margin
Source: DNB Markets, Companies
24 |
Agenda
E&P spending – Recovery is still off the horizon
Drilling sector
Subsea sector
Seismic sector
Offshore supply
Appendix
25 |
Too high expectations of a recovery
 Despite resent correction we find hope of a sift recovery still too high
 Consensus expects revenue decline in 2016 of 15% and 12% growth in 2017
 Share prices leading revenue by 6-12 months, makes as believe that it is too early to positon for a recovery
Market cap versus 1-year forward revenues
25,000
1200
50%
40%
1000
20,000
30%
Market cap
800
20%
10%
-10%
15,000
600
10,000
400
5,000
200
-20%
-
-30%
0
-40%
2004
2005
2006
2007
2008
2009
Offshore E&P Spending (DNB)
2010
2011
2012
2013
2014 2015e 2016e 2017e
Seismic revenue growth (cons.)
Market cap
Rev 12m fwd
26 |
12 month forwardRevenues
E&P spending vs seismic revenue growth
60%
Worst is yet to come
 Current vessel market extremely dependent on a few countries
 Focus on development capex from oil companies with more downside potential on exploration budgets
 Larger cuts in exploration budgets announced already with Chevron cutting exploration by 65%
Vessels working in Myanmar, Brazil and Mexico
More downside on exploration budgets
100%
14
45%
12
40%
90%
35%
80%
30%
70%
8
25%
60%
6
20%
10
15%
4
10%
2
0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
2011
2012
Brazil
Mexico
2013
Myanmar
2014
2015
2016
Share of international fleet (r.h)
21%
18%
19%
19%
2006
2007
2008
2009
2010
Production
19%
19%
17%
17%
17%
15%
2011
2012
Exploration
2013
2014
2015e
2016e
19%
50%
40%
5%
30%
0%
20%
10%
-
27 |
Disappointing licensing rounds – “The Brazil case”
 Significant decline in licensing a leading indicator for vessel demand
 Oil companies unwilling to commit exploration programs
License round activity Brazil
90
License round activity US GoM (Western Round)
2
2,500,000
600,000,000
80
70
500,000,000
2,000,000
1.5
400,000,000
50
1
40
30
bnUSD
# of blocks
60
1,500,000
300,000,000
1,000,000
200,000,000
0.5
20
500,000
100,000,000
10
0
0
Round 1 Round 2 Round 3 Round 4 Round 5 Round 6 Round 7 Round 9 Round 11 Round 13
(1999)
(2000)
(2001)
(2002)
(2003)
(2004)
(2005)
(2007)
(2013)
(2015)
Awarded Blocks (l.h)
Min work program (r.h)
-
2005
2006
2007
2008
2009
Acres bid on (l.h)
2011
2012
2013
2014
2015
Total Bonus High Bid (r.h)
28 |
Lack of new regions emerging – “The Myanmar dilemma”
 Seismic market dependent on new emerging markets
 Strategic shift away form frontier exploration negative for vessel market
 Due to timelag from rounds are announced the damage is already done
Vessels in emerging regions
Time line for Myanmar activity
12%
10%
8%
6%
mid-2013
4%
early-2014
Round
announced
2%
0%
Q1
Q2
Q3
2011
Q4
Q1
Q2
Q3
Q4
Q1
2012
Angola (pre-salt)
Q2
Q3
Q4
2013
Uruguay
Q1
Q2
Q3
Q4
2014
Gabon
Q1
Q2
Q3
2015
2014/15
PSC signed
H1 2015
2016
First seismic
Q4
Blocks
awarded
~2 year lag from
award
Majority of
seismic
29 |
Supply aid, but no rescue
 Newbuilds and return of idle vessels countering the help from stacking of older vessels
 Much of self help initiatives have been taken already without improving the market
 Stacking is no sign of market improvement (remember CGG in Dec 2013)
Number of 3D vessels
Number of practical streamers on 3D vessel fleet
70
700
60
1
11 58
50
2
49
7
64
3
4
65
4
2
600
63
14
4
108507
53
16
400
40
0
30
0
500
37
4
0
1
34
300
2
36
6
385
56
435 69 45
12
411
51
2
558
46
20 28
602
610132
42
520
166
28 0
326
50 28 16
200
20
100
10
0
0
30 |
0 30
320
350
Expect reshuffling on cost curve
 Risk of restructured companies emerging with lower all in cash cost
- Polarcus restructuring, CGG refinancing, former Dolphin vessels in new set-up?
 Current dayrates unsustainable only under current capital structures
 PGS all in cash cost similar to high-end end vessel rates
- Maintenance capex USD80m below normalized (USD24k per day)
- Bond and term-loan non-amortizing (USD843m at 7-year profile = USD35k per day)
Dayrate versus all-in cost structure
USDk/day
Cash cost curve (PGS reported)
450
400
350
300
250
200
150
100
50
0
PLCS
(old)
2007
PGS vessels
Competitors' vessels
2008
2009
2010
2011
2012
2013
2014
PLCS
(refin)
2015
PGS
(curr)
2016e
OPEX
CAPEX
Debt service
3D 16+ streamers
3D 12-14 streamers
3D 10-12 streamers
31 |
PGS
(norm)
2017e
Agenda
E&P spending – Recovery is still off the horizon
Drilling sector
Subsea sector
Seismic sector
Offshore supply
Appendix
32 |
Challenging market environment set to continue
 Demand for OSV vessels set to continue to decline the coming years as offshore activity is falling…
 …while the OSV fleet continues to grow
 Vessel owners effort to stack vessels should benefit the market to some extent…
 … but scraping of older tonnage is needed to bridge the wide supply and demand gap.
Supply and demand PSVs
Supply and demand AHTSs
1,600
1,800
1,400
1,600
1,200
1,400
1,200
1,000
1,000
800
800
600
600
400
400
200
200
-
-
Implied demand
PSV fleet
Implied demand
AHTS fleet
Source: DNB Markets, IHS Petrodata
33 |
We expect dayrates in the OSV sector to remain depressed
 We forecast 2016-2018 PSV dayrates at marginal cost, slightly up from average 2015 levels
 2016-2018 AHTS rate expected to be at par with average 2015 levels
 Utilisation expected to continue to decline slightly in 2016 after a steep decline in 2015
PSV day rates (USD/day)
AHTS day rates (USD/day)
Spot utilisation
60
120
90%
50
100
80%
40
80
30
60
20
40
10
20
-
-
70%
60%
Opex
3,000 - 4,000 dwt
> 4,000 dwt
40%
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016e
2017e
2018e
2018e
2017e
2015
2016e
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
50%
Opex
< 10,000 bhp
10,000-20,000bhp
> 20,000 bhp
30%
PSV
AHTS
Source: DNB Markets, IHS Petrodata
34 |
Subsea construction market not shielded from the downturn
Significant fleet growth
 Weaker market outlook has triggered offshore construction companies to trimming down their charted-in fleet
 Seasonal contracts have become more common in the industry
 OCV utilisation is trending downwards, decline most profound for the light assets classes; which the OSV companies typically owns
 OSVs companies key clients’ (Tier 1 Subsea construction) backlog is down 25% YOY
Significant fleet growth
Declining utilisation
70
700
60
600
50
500
40
400
30
300
20
200
10
100
1970
1972
1974
1976
1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016e
-
Small (<100m)
Medium (100-125m)
Large (>=125m)
Total
Tier 1 backlog down 25% YOY
0.9
30
0.8
25
0.7
20
0.6
15
0.5
10
0.4
0.3
Jan-08
5
Jan-10
Jan-12
Jan-14
Jan-16
Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3 Q1 Q3
Diving Support
ROV Support
Pipelay
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Source: DNB Markets, IHS Petrodata
35 |
Unsustainable capital structure
NIBD to EBITDA
 The recent newbuild period has been fuelled by easy access to bank debt and unsecured bond financing
 Current leverage is at an very high level with NIBD to EBITDA above 10.0x in 2017-2018
 The current market capitalisation comprises less than 10% of the enterprise value for most the companies, which unsustainable low
 Solution need to include some sort of debt reduction, either by injection of capital, debt conversion and/or haircut to existing loans
NIBD to EBITDA
Capital structure (NOKm)
20.0x
100%
17.5x
18.0x
80%
16.0x
14.0x
12.4x
12.0x
9.9x
10.0x
8.0x
90%
70%
60%
93%
95%
99%
5.1%
1.2%
Farstad
Shipping
Havila
Shipping
88%
94%
30%
20%
4.0x
10%
-
98%
40%
7.0x
6.0x
2.0x
83%
50%
16.7%
7.2%
1.8%
0%
Deep Sea
Supply
DOF
Eidesvik
Offshore
11.9%
Market capitalisation
Siem Offshore
NIBD + other
Source: DNB Markets, Companies, Bloomberg
36 |
6.2%
Solstad
Offshore
Offshore Supply companies at the mercy of the credit market
Debt schedule
4,000
Bond overview
 Our base case is that the banks will stretch a long way to avoid loan losses (i.g. extending
maturity, deferring instalments and PIK interest)
3,500
3,000
2,500
 However, we believe the banks is very reluctant to increase its exposure to the sector.
2,000
1,500
 The main problems arises when the unsecured bonds matures as the companies have
limited refinancing options
1,000
500
-
 We find the refinancing of Havila Shipping and DOF as the most challenging
2016
2017
2018
Bond maturity
1,400
1,200
1,000
800
600
400
200
-
2016
2017
2018
2019
Bond overview
Company
DOF Subsea
DOF
DOF
DOF Subsea
DOF
Eidesvik Offshore
Farstad Shipping
Farstad Shipping
Havila Shipping
Havila Shipping
Havila Shipping
Havila Shipping
Siem Offshore
Siem Offshore
Solstad Offshore
Solstad Offshore
Bond Name
DOFSUB05
DOF09
DOF11
DOFSUB07
DOF10
EIOF01
FAR03
FAR04
HAVI08
HAVI04
HAVI07
HAVI06
SIOFF01
SIOFF02
SOFF03
SOFF04
Amount
Issued Currency outstanding
29.04.2011
NOK
750
07.02.2012
NOK
700
07.02.2014
NOK
700
22.01.2013
NOK
1,300
12.09.2012
NOK
700
22.05.2013
NOK
300
15.02.2012
NOK
400
29.05.2013
NOK
1,000
30.08.2012
NOK
500
08.11.2010
NOK
162
30.03.2011
NOK
236
30.03.2011
NOK
236
30.01.2013
NOK
600
28.03.2014
NOK
700
25.02.2011
NOK
700
24.06.2014
NOK
1,000
Maturity
quarter
Q2-2016
Q1-2017
Q1-2018
Q2-2018
Q3-2019
Q2-2018
Q1-2017
Q2-2018
Q3-2016
Q4-2016
Q1-2017
Q1-2017
Q1-2018
Q1-2019
Q1-2016
Q2-2019
Coupon
Yield
6.61%
10.00%
8.34%
37.30%
5.84%
29.41%
6.13%
14.80%
8.08%
23.23%
5.67%
18.83%
5.36%
52.65%
4.56%
33.72%
9.66% 365.56%
4.85%
90.26%
5.71%
58.77%
8.60%
84.00%
5.85%
23.25%
5.63%
21.08%
5.60%
17.68%
4.73%
19.40%
Last
trade
99.0
75.0
64.0
82.8
63.0
75.0
62.0
53.0
20.0
55.0
55.0
54.6
72.0
64.0
98.6
63.0
Bid price
99.01
75.01
64.00
82.77
62.98
74.98
62.01
53.01
20.00
55.00
55.00
54.59
72.00
64.00
98.57
63.00
Source: DNB Markets, Companies, Bloomberg
37 |
Ask price
99.60
79.58
67.74
85.63
66.07
79.87
66.66
57.85
27.64
65.00
65.00
65.00
77.00
69.00
99.42
68.00
Agenda
E&P spending – Recovery is still off the horizon
Drilling sector
Subsea sector
Seismic sector
Offshore supply
Appendix
38 |
E&Ps were planning for a significant increase in the oil price
 Average planning oil price of USD66/bbl for 2016 and USD75/bbl long-term*
 Oil price comfort zone has fallen significantly since last year (high-40s to high-70s)
 Further downside risk to near- to medium term spending if we do not see meaningful improvement in commodity prices
Oil price assumptions*
Oil companies' comfort zone (USD/bbl)*
140
140
120
120
100
100
80
80
60
60
40
40
20
20
0
Survey '07 Survey '08 Survey '09 Survey '10 Survey '11 Survey '12 Survey '13 Survey '14 Survey '15
Current year
Next year
Long-term
Brent price
0
Survey '07 Survey '08 Survey '09 Survey '10 Survey '11 Survey '12 Survey '13 Survey '14 Survey'15
Comfort zone
Brent price
Source: DNB Markets, Companies, Bloomberg
* Results from our August 2015 E&P spending report
39 |
Will new offshore production offset base decline near term?
Offshore production scenarios with different decline rates
(mmbbl/day)
30
Production growth from 2015 to 2018 with different decline
rates
5%
4%
29
1%
28
-
27
26
-2%
-5%
25
-5%
24
23
-7%
-10%
-10%
22
21
-12%
-15%
20
-15%
2010
2011
History
2012
3.0%
2013
4.0%
2014
5.0%
2015
2016
6.0%
2017
7.0%
2018
8.0%
-20%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
9.0%
Source: DNB Markets
40 |
10.0%
Cash flow situation Majors
350
80
300
70
250
60
200
50
40
150
30
100
20
50
10
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 LTM*
Q1-2014
Capex
Dividend and Share buyback
Net OCF
Capex
Q2-2014
Q3-2014
Q4-2014
Q1-2015
Dividend and Share buyback
Q2-2015
Net OCF
Source: DNB Markets, Companies
41 |
Q3-2015
US shale production has been more resilient than expected
Production versus capex (US shale aggregate)
100
90
80
70
60
50
40
30
20
10
-
Cash flow situation shale aggregate
3,000
35
2,500
30
2,000
25
1,500
20
1,000
15
500
-
10
5
Q1-2014
Capex (USDbn) - L.H.
Production (mmboe) - R.H.
Q2-2014
Capex
Q3-2014
Q4-2014
Q1-2015
Q2-2015
Dividend and Share buyback
Q3-2015
Net OCF
Source: DNB Markets, Companies
42 |
USD65-75/boe is the new USD100-110/boe
USD65-75/boe is the new USD100-110/boe
120
100-110
~10
~10
100
~2
~10
80
~65-75
60
40
20
Old oil price level
Oil service
deflation
Reduced
complexity and
standardization
Cost cutting in
E&Ps
Lower tax and
E&P profitability
New oil price
level
Source: DNB Markets
43 |
Production growth failed to materalize in 2014 (yet again)
 Offshore focused oil companies guided on 3% production growth in 2014 – actual production fell 1%
 YTD (as of end-Q3) the Majors have increased production by 3% compared to 2014
 Consensus view is that capex reductions will lead to falling production over the next years
Capex vs production for majors
2015 and 2016 production guidance*
4.0%
3.5%
2.8%
2.7%
3.0%
2.9%
2.0%
1.0%
-1.0%
-2.0%
-0.8%
-1.2 %
2013
2014
Guidance (t-1)
2015e
2016e
Actual
Source: DNB Markets, Companies, ENI
* Updated in August 2015
44 |
Drilling - Fleet statistics
 Including stacked rigs and orderbook the floater fleet stands at
352 rigs
 Including stacked rigs and orderbook the floater fleet stands at
668 rigs
 Floater demand
 Peak (2014): 280 rigs
 Bottom (1994): 120 rigs
 Average (1990-2015): 177 rigs
 Jack-up demand
 Peak (2014): 450 rigs
 Bottom (1999): 283 rigs
 Average (1990-2015): 348 rigs
Floater fleet
Jackup fleet
400
600
47
350
37
64
500
43
300
15
33
95
127
400
250
51
44
200
150
300
509
314
268
509
200
100
100
50
-
0
Year-end
2013
Newbuilds
delivered
Retired rigs
Cold stacked
Warm/Hot
stacked
Current
Orderbook
Potential
active fleet
Year-end 2013
Newbuilds
delivered
Retired rigs
Cold stacked
Warm/Hot
stacked
Orderbook
45 |
Potential
active fleet
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46 |