North Sea Drilling Outlook: Future Looking Brighter?
SIMMONS & C OMPANY INTERNATIONAL
Oil Service Industry Research January 8, 2004
North Sea Drilling Outlook: Future Looking Brighter? The North Sea offshore drilling market has suffered from weakening demand, oversupply of units and a resultant fall in day rates over the last three years. Our analysis suggests that fleet utilization will improve, potentially significantly (15%), in 2004. However, this improvement is a function of reduced supply rather than increased demand and we therefore believe significant increases in day rates are unlikely. Notwithstanding these comments, the North Sea jack-up rig market remains significantly healthier than the floater market and continued strong utilization provides the opportunity for attractive day rates during peak activity.
Ruairidh (Rory) Stewart +44 1224 202328 [email protected]
*Important disclosures appear at the end of this report.
North Sea Rig Market Outlook
Pros •
Cons Based on rigs currently contracted and visible
•
The improvement in utilization is being driven by
tenders, demand appears essentially flat with 2003
reduced supply rather than increased demand, thus
but supply is reduced by 12 units.
day rate gains are likely to come in small increments over time.
•
Utilization could improve by 15% to roughly 80% for floaters and by 12% to essentially 100% for
•
The North Sea is still dominated by major oil
jack-up rigs increasing the possibility for day rate
companies focused on investment opportunities
appreciation for jack-ups.
outside the North Sea. The North Sea ranks poorly in global competition for funds.
•
It is difficult for units to return to North Sea without longer term contract / high day rates, thus we do not
•
expect supply to expand meaningfully.
The pace of majors divesting quality assets is likely to remain slow as the North Sea remains an important source of cash for deployment elsewhere.
•
From an E&P perspective, strong commodity prices make the North Sea a highly attractive investment
•
opportunity.
The North Sea is maturing and the average development size is declining. This secular trend is uninspiring for future drilling activity.
•
st
The 21 Licensing Round in the U.K. (July 2003) awarded 88 licenses on which prospects could be
•
developed for drilling during 2004.
The high cost of drilling / development is a barrier to smaller companies wishing to enter the North Sea E&P sector.
•
Recent U.K. Government actions have lowered barriers to exploration in the U.K. o
100% capital allowance
o
Exploration supplement for new entrants
o
Promote licenses
o
Action on access to infrastructure
•
Recent exploration results in Norway / Faroes / West of Shetland have been disappointing.
•
Recent changes to U.K. fiscal policy are discouraging for the industry as a whole. There is fresh disappointment that capital allowances for
•
Activity is projected to increase on those assets
exploration were not increased to 125-150%
divested by the majors (e.g. Apache Forties, CNR
following recent consultation process.
Ninian). • •
Norway is similarly encouraging as the government
are generally more spasmodic and related to
has reopened activity in the Barents Sea and offered
commodity prices. This adds uncertainty to the
th
significant acreage in the 18 Licensing Round. •
Relative to majors, independents activity programs
outlook for drilling contractors.
Cooperation agreement between U.K. and Norway opens up potential development opportunities along the median line between the two countries.
•
Large scale developments including Snohvit, Ormen Lange, Buzzard, Clair and Goldeneye will require development drilling programs during 2004-2006.
2
SIMMONS & COMPANY INTERNATIONAL
North Sea Market Context Over the last twenty years, the North Sea has on average represented approximately 23% of international offshore mobile rig activity. North Sea demand has been on a downward trend since 1985 driven by weaker U.K. activity levels. Norwegian activity has increased in recent years but this has been insufficient to offset declines in the U.K., which now accounts for under 50% of total North Sea rig demand. North Sea rig demand peaked in 1985 at an average of 90
U.K. activity levels have historically dominated the North
rigs (peak month July 1985 at 96 rigs). Since that time,
Sea market (65% to 70% of rig demand), but this is no longer
demand has fluctuated widely but has remained on a
the case with the U.K. representing 42% of North Sea
downward trend. External influences such as commodity
activity in 2003. While rig demand in Norway has been
prices are an important driver of North Sea activity, reflected
increasing in recent years, this has been insufficient to offset
in record low drilling demand of 28 rigs in October 1999
the overall decline in North Sea demand due to weakness in
following Brent crude hitting $10 barrel. Activity has since
U.K. activity levels. In 2003, Norway and the U.K. each had
recovered but remains well below 1985 levels. This is
average rig demand of 19 units, equal to 42% of total North
particularly disappointing given the strong commodity prices
Sea rig demand. The remaining 16% of demand was made
that have prevailed since 1999 which the industry has not
up equally by the Netherlands and Denmark which have
converted into higher activity levels. This disconnect can be
remained important activity centres, particularly for the jack-
attributed to the relative unattractiveness of new investment
up market.
opportunities in the North Sea versus other regions, at least for the major oil companies who dominate the basin. North Sea Offshore Rig Demand By Country (Average Annual Rig Demand And % Of Total) 100
100% Denmark
90
Norway
70
U.K.
Percentage of North Sea Rig Demand
Annual Average Rig Demand
Netherlands 80
60 50 40 30 20
80%
60%
40%
Denmark Netherlands Norway U.K.
20%
10 0 1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
0% 1982
2002
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Sources: Baker Hughes Rig Count and Simmons & Company International.
U.K. Rig Count Vs. Brent Oil Price
U.K. Wells Drilled (1990-Q3 2003)
70
35
300
30
250
50
25
200
40
20
30
15
20
10
U.K. Wells Drilled
U.K. Rig Demand
Oil Price (RH Scale)
Brent Oil Price ($ / bbl)
Rig Demand 60
Exploration Appraisal Development
150
100
50
U.K. rig demand trend line.
1986
1988
1990
1992
1994
1996
1998
2000
20 01
20 00
19 99
19 98
19 97
19 96
19 95
19 94
2002
20 02 20 03 To Q3
1984
19 93
0 1982
19 92
0
0 19 91
5
19 90
10
Sources: BHI Rig Count, Bloomberg, U.K. Department of Trade & Industry (DTI) and Simmons & Company International.
SIMMONS & COMPANY INTERNATIONAL
3
North Sea Rig Market Outlook For 2004 We believe the North Sea rig market will realize higher fleet
In response to these tighter conditions, jack-up day rates have
utilization in 2004 compared to 2003. While this is primarily
been more resilient than semi day rates but are still below
a supply led phenomenon, there are a number of positive
peak 2001 levels. This corresponds to a global softening in
demand catalysts that could drive an improved market in the
market conditions and the overhang from semis in the
medium term. These factors include i) major oil companies
market.
divesting assets; ii) drilling on acreage from recent U.K. licensing round and; iii) opening of the Barents Sea southern
North Sea Standard Jack-up Day Rates
area. These issues are discussed in more depth under the
$100
specific country sections. We believe day rates should appreciate to 2001 levels ($80k / day for standard jack-ups, $90k / day for standard semis). In short, the market looks to be “OK” in 2004 but without a global improvement in demand there will, on the whole, be adequate supply to
Day Rates ($'000 / Day)
$80
improve incrementally during 2004 but are unlikely to
$60
UK
$40
Netherlands
$20
satisfy demand and curtail opportunities for significant day rate improvements.
$0 Jan'01
Apr
Jul
Oct
Jan'02
Apr
Jul
Oct
Jan'03
Apr
July
Oct
Jack-ups
Sources: Platts, Simmons & Company International.
The North Sea jack-up market is much tighter than the floater
Looking ahead into 2004 there is currently 14.3 rig years of
market and we would expect this to continue through 2004.
work already contracted providing a base utilization of 45%.
Jack-up demand is not as concentrated in the U.K. and
This is down slightly year on year from 18.4 rig years of
Norway as the floater market (U.K. 36% of 2003 demand,
demand contracted 12 months ago for 2003 (54% utilization).
Netherlands 27%, Denmark 27% and Norway 9%) and the
However, in addition to the units currently contracted, we
current fleet is comprised of 32 units with 30 currently
also have visibility on tenders totaling 10.2 rig years of
working (94% utilization). While in the very short-term the
demand in 2004 (peak of 14 units in July and September).
market is likely oversupplied by one to two units, these can
This is significantly higher than tenders in the market 12
be quickly consumed as activity picks up in the summer
months ago for 2003 and helps compensate for the lower
months leading to full utilization. Since early 2003, a net two
levels of forward activity currently contracted.
units have left the North Sea further improving the prospects of a tight demand / supply balance.
Snapshot Forward 1 Year Utilization ‘03 vs. ‘04 100% 90%
North Sea Jack-up Rig Disposition 2003
80%
100% Rig Utilization
90% 80% 70% 60%
60% 50% 40% 30%
50%
20%
40%
10%
Available 30%
0%
Working
1
20%
6
11
16
21
26
36
41
46
Sources: Platts, OneOffshore, Simmons & Company International. Feb-03
Apr-03
May-03
Jul-03
Aug-03
Sep-03
Nov-03
Dec-03
Sources: Platts, Simmons & Company International.
4
31
Week
10% 0% Jan-03
Jack Up Fwd Util - 2003 Jack Up Fwd Util - 2004
70%
SIMMONS & COMPANY INTERNATIONAL
51
Rig Market Outlook For 2004 (continued)
Additional tenders will likely emerge as 2004 progresses and
This is particularly the case in the northern sector of the U.K.
it is notable that approximately 12.9 rig years of additional
North Sea and the Norwegian North Sea. There are currently
tenders came out during 2003 (although slightly over 5.5 rig
40 floaters in the North Sea fleet, with only 22 working (54%
years failed to progress to actual activity). Assuming a
utilization), 11 available and seven cold stacked. Current
similar level of tendering during 2004, demand could
demand of 22 units is similar to the 2002-2003 holiday
increase by two rig years driving utilization to essentially
period but the supply side of the equation has improved
100% and creating very tight conditions during peak
significantly since then. In late December 2002 there were
activity in Q3’04.
45 floaters in the North Sea, only three of which were cold stacked. Since that time, five units have left the North Sea
North Sea Jack-Up Market Summary 2003-2004E Fleet At Start
North Sea Jack-Up Market 2003 2004 34.0 32.0
Contracted Demand At Start Visible Tenders At Start Tenders During Year Total Potential Demand Actual Demand
18.4 4.1 12.9 35.4
Change -2.0
14.3 10.2 12.9 37.4
-4.1 6.1 0.0 2.0
29.9
31.9
2.0
Tenders Not Progressed
5.5
5.5
0.0
Utilization (based on Jan fleet)
88%
100%
12%
while an additional four units have been cold stacked. We also anticipate a further unit leaving the North Sea within the next month. Therefore, the readily available floater rig count will have been reduced by 10 units in 13 months – the major positive influence in this market. North Sea Floater Fleet Disposition 2003 100%
80%
60%
Sources: OneOffshore, Simmons & Company International.
40%
Available Cold Stacked
Looking at tenders currently visible, companies such as
Working
Venture Production, Petro-Canada, ATP and DNO do not
20%
have any visible tenders in the market at present. However, 0% Jan-03
these companies do have emerging drilling programs. For example, Venture Production will likely drill four to five
Feb-03
Apr-03
May-03
Jul-03
Aug-03
Sep-03
Nov-03
Dec-03
Sources: Platts, Simmons & Company International.
wells in 2004 plus several well workovers which could add between 0.5-0.8 rig years of demand. If our projections
Due to excess capacity, day rates have moved sharply
prove overly optimistic, a repeat of 2003 average demand of
downwards for North Sea semi-submersibles (semis) over the
29.9 rigs equates to utilization of 93% in 2004 - enough to
last three years. At current levels, day rates offer a thin
keep the jack-up market in good health during the year.
margin above cash costs - this explains contractor’s motivation to cold stack rigs.
Increased utilization will lead to improved day rates for the jack-up fleet. However, we do not anticipate a surge in rates,
North Sea Standard Semi Day Rates
but rather incremental improvement. In our opinion, the
$160
global rig surplus and the overhang in the North Sea floater
$140
market will serve to dampen rate potential during 2004.
The floating rig market will likely remain oversupplied throughout 2004. The North Sea floaters market is driven by
Day Rates ($'000 / Day)
Floaters
UK $120 Norway $100
$80
$60
$40
U.K. and Norwegian drilling activity (50% & 40% of 2003 demand respectively) and has suffered from declining demand in both areas.
$20 Jan'01
Apr
Jul
Oct
Jan'02
Apr
Jul
Oct
Jan'03
Apr
July
Oct
Sources: Platts, Simmons & Company International.
SIMMONS & COMPANY INTERNATIONAL
5
Rig Market Outlook For 2004 (continued)
Many of the available units are being marketed globally, and
Assuming a similar pattern for new tenders (and failure of
once a rig leaves the North Sea it is unlikely to return without
some tenders to progress to actual work) we anticipate
the incentive of a significant contract term or increased day
slightly lower floater demand of 25.4 rig years in 2004.
rates. Additionally, several rigs leaving the North Sea will
However, this would result in much improved utilization - to
need upgrades to come back into the market, having been
an average of nearly 80% due to the reduction in fleet size.
given exemptions from regulations introduced while the unit was working in the North Sea (i.e. accommodation
North Sea Floater Market Summary 2003-2004E
standards). This will act as a further deterrent for units to reenter the market.
Fleet At Start Cold Stacked Available Fleet
Looking ahead into 2004, floaters currently contracted total
North Sea Floater Market 2003 2004E 45.0 39.0 3.0 7.0 42.0 32.0
Change -6.0 4.0 -10.0
Contracted Demand At Start Visible Tenders At Start Tenders During Year Total Potential Demand
13.7 7.5 11.8 33.0
13.3 6.2 11.8 31.3
-0.4 -1.3 0.0 -1.7
Taking the same snapshot 12 months ago for 2003 would
Actual Demand
27.0
25.4
-1.7
have yielded a similar contracted demand level (13.7 rig
Tenders Not Progressed
5.9
5.9
0.0
Utilization (based on Jan fleet)
64%
79%
15%
13.3 rig years of demand and provide contracted utilization of roughly 34% as it stands today. Excluding cold stacked units, current average utilization is 41% for next year.
years) but average contracted utilization of 33% due to the greater number of units in the market (excluding cold stacked
Sources: OneOffshore, Simmons & Company International.
units). Overlaying 2003 demand with current fleet statistics Snapshot Forward 1 Year Utilization ‘03 vs. ‘04
highlights the potential improvement in utilization due to fleet rationalization.
70%
60%
Floater Fwd Util - 2003 Floater Fwd Util - 2004
2003 Floater Demand Versus 2004 Fleet
Rig Utilization
50% 100% 40% 80% 30% 60%
20%
10%
40% 1
6
11
16
21
26
31
36
41
46
Available Cold Stacked
51
Week
Sources: Platts, Simmons & Company International.
In short, fundamentals for the North Sea floater market have modestly improved due to a reduction in total fleet capacity and an increase in cold stacked rigs. Looking more closely at 2004, currently visible tenders provide an additional 6.2 rig years of demand (peak of 11 units in May’04) in addition to the 13.3 rig years already contracted. More tenders will emerge over the next 12 months. For example, in 2003 an additional 11.8 rig years of demand emerged during the year
Working 20%
0% Jan-04
Feb-04
Apr-04
May-04
Jun-04
Sep-04
Nov-04
Dec-04
Sources: OneOffshore, Platts, Simmons & Company International.
As a result, we envisage U.K. day rates improving but remaining relatively constrained (approximately $55-60k during the summer peak in activity) and well short of the $80-100k rates enjoyed during 2001.
(peaking at 21 units in August) from total tenders of 17.5 rig years (some tenders do not progress to actual activity). Just under five rig years of demand was generated by short-term camp aigns for independents.
6
Aug-04
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – U.K. As the U.K. North Sea matures as a hydrocarbon basin,
U.K. Government Actions
drilling activity has declined significantly due to less exploration and decreasing size of developments. One of the
The U.K. Government has stated it is committed to ensuring
key questions emerging from this analysis is the likelihood of
the maximum possible exploitation of oil and gas resources
any recovery in U.K. activity levels. This is a subject area
in the U.K. Within this broad aim are a number of specific
we have touched upon many times (see our reports on U.K.
initiatives to encourage new players into the North Sea.
issues from October 2001, May 2002 and February 2003) and
These include the fallow field initiative, infrastructure access
we do not wish to rehash that analysis here. However, key
(transportation and processing), cooperation with Norway,
factors to indicate improving fundamentals in the U.K. are i)
new licensing and adjustments to the fiscal regime.
transition of asset ownership from majors to independents, ii) government actions and iii) future field developments.
Fallow Fields
Transition Of Asset Ownership From Majors To
The fallow field initiative seeks to encourage activity on
Independents
licenses that have turned fallow, i.e. have had no activity (seismic, drilling etc.) for a number of years. In 2002, over
We have previously emphasized the impact smaller
200 blocks were identified as “fallow” and owners were
independent players could have in driving a renaissance for
instructed to “use it or lose it”. Since that time over 100
the U.K. industry – similar to the Gulf of Mexico in the mid
blocks have been taken out of the fallow category as 39 have
1990’s. However, after getting off to a fanfare start in 2003
been relinquished, 28 exploration and appraisal wells have
with BP selling Forties to Apache, asset disposals by major
been drilled, nine seismic surveys have been conducted and
oil companies have been relatively disappointing.
one block is producing. With a further 172 blocks estimated to turn fallow in 2003 the Government is hoping to accelerate
The impact of divestments when they occur and the
this initiative and force existing owners to invest or release
momentum offered by new players is evidenced by activity in
the acreage to those that will.
2003 and current plans. We estimate these smaller players (e.g. Venture Production, Apache, CNR, ATP, Ramco,
Access To Infrastructure
Pertra, EnCana etc.) brought an additional five to seven rig years of work into the market in 2003. Apache’s recent
Major oil companies dominate platform and pipeline
contract with Global Santa Fe’s Galaxy I and Galaxy III rigs
infrastructure. The issue of tariffs charged by the majors for
for drilling over the Forties Echo platform is another good
new developments being tied into their infrastructure has
example of an aggressive program being put together by new
been raised by many participants as a roadblock in
asset owners. Asset disposals by the major oil companies is
maximizing opportunities in the U.K. North Sea. Progress
good news for the drilling market but we remain concerned
has been made on this issue over the last few months. The
that divestment of reasonable quality properties will occur at
Department of Trade and Industry (DTI) expects tariffs
a slow pace. Such assets generate attractive cash flow at
(which in some circumstances have represented 45% of total
current commodity prices – very useful for companies
field costs) to come down in the future and has pressed
investing huge sums in less mature / higher growth potential
infrastructure owners to follow a code of practice, show
areas such as West Africa, deepwater Gulf of Mexico and the
processes are in place to set fair and reasonable tariffs, make
FSU. We therefore reiterate our belief that disposals will
tariffs more transparent and put in place a mechanism for the
continue but remain incremental in nature and that major oil
DTI to intervene in negotiations. These changes should
companies will continue to dominate the U.K. industry.
ensure that infrastructure owners do not take a disproportionate share of the rewards from new field developments.
SIMMONS & COMPANY INTERNATIONAL
7
Activity Drivers – U.K. (continued)
Cooperation With Norway
This last point will mean new entrants without a profit stream in the U.K. will be less disadvantaged due to their inability to
The recent agreement signed between the U.K. and Norway
absorb capital allowances in Year one. The industry had
not only paves the way for the giant Ormen Lange gas field
been pushing for an increase in exploration and appraisal
development, but also allows more flexible use of
capital allowances to 125% but the Government has decided
infrastructure on both sides of the median line. This will
the case for this has not been proven (a disappointment for
likely result in a life extension for U.K. infrastructure
the industry who had suggested this could increase
(processing / transporting Norwegian hydrocarbons) thereby
exploration drilling by two to three wells per annum).
extending the timeframe to exploit resources situated near infrastructure and will also help increase activity around the
Future Developments
median line between the U.K. and Norway. The outlook for new field developments in the U.K. is very New Licensing
mixed. Current forecasts from Deloitte & Touch suggest a total of 61 new field developments between now and 2008
The introduction of “Promote Licenses” in the U.K. 21
st
although it is likely that many scheduled in 2004 and 2005
licensing round (May 2003) lowers the threshold for
will slip. The economic reserves accessed by these
companies to win acreage in the U.K. The promote licenses
developments total 2.7bn boe (average reserve size is 44mm
charge lower acreage fees and companies do not have to pass
boe).
financial, technical and environmental competency tests that apply to traditional license. The license provides the holder
Future U.K. Field Developments
with a two year opportunity to assess and promote the prospectivity of the acreage before they need commit to drilling a well or displaying the financial, technical and environmental competencies to do so. Fifty-three such licenses were awarded in May 2003 and it is possible that the more serious license winners may be in a position to seek funding / partners to start drilling in mid-2004.
Start Date
Economic Reserves No. DevelopOil Total Average ments (mmbbls) Gas (bcf) (mmboe) (mmboe)
2004 2005 2006 2007 2008 Total
23 22 7 8 1 61
512 208 713 111 147 1,691
2,523 2,023 501 829 0 5,876
933 545 797 249 147 2,670
41 25 114 31 147 44
Sources: DTI, DTPS, Simmons & Company International.
Fiscal Regime The key developments over the next few years are EnCana In the April 2002 budget, the U.K. Chancellor introduced a
Buzzard, BP Clair and Shell Goldeneye. These three fields
10% corporation tax surcharge on profits from U.K. oil and
account for 945mm boe or 35% of the total from 61 future
gas extraction. At the same time 100% capital allowances
developments. Excluding these three larger fields, the
(amount of investment deductible for tax purposes in fiscal
average development size falls to 30mm boe. These smaller
year – in lieu of depreciation) were introduced to encourage
developments will generally be comprised of a subsea tie-
new investment. These changes were greeted with dismay by
back or unmanned platform utilizing existing infrastructure
the industry although our analysis suggested that companies
for processing and export. More importantly, in the context
who were investing in new developments were only
of this report, drilling requirements are generally minimal for
marginally negatively impacted (see May 2002 report).
such developments – perhaps two to three wells per
Since then the Government has abolished the 12.5% Royalty
development.
charged on pre 1982 fields and PRT on new field developments. Most recently, the Chancellor announced that 100% capital allowances will be carried forward with interest for investments in exploration.
8
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – U.K. (continued)
In contrast, the Buzzard development (~550mm boe) will be
On the exploration side, the leading drillers in 2003 were
comprised of three platforms and EnCana has a tender for
Kerr McGee and EnCana with six wells apiece. Into 2004
drilling 10 firm wells plus 20 option wells starting H2’05.
these two companies are expected to maintain that pace with
EnCana will also pursue exploration opportunities close to
Kerr McGee potentially drilling four to six wells in the
Buzzard to tie back discoveries and keep the platform fully
Central North Sea next year while EnCana is expected to drill
utilized. The BP Clair development (Phase I ~ 270mm boe)
five exploration and appraisal wells.
will have 15 producing wells and eight water injection wells while Shell Goldeneye will produce through five production
Exploration activity beyond 2004-05 will depend on the
wells which are being drilled currently.
success achieved by those companies now aggressively pursuing opportunities, such as EnCana and Kerr McGee. Failure to follow up Buzzard with other meaningful
U.K. Total Oil & Gas Resource Base
discoveries will inevitably result in lower exploration activity Discovered 18.9bn boe
in the longer term. At a fundamental level this should be
Oil 5.3bn boe
expected given the maturity of the basin. According to DTI estimates, there are still significant resources to be found in
Undiscovered 8.6bn boe
the U.K. – between 3.5bn boe and 22bn boe. However, these estimates are subject to revision and are speculative – we have used the central case of 8.6bn boe in the chart above. While these potential volumes are meaningful, they must be
Gas 3.3bn boe
Produced 32.8bn boe
viewed in the context of a basin that has produced 33bn boe to date.
Sources: DTI and Simmons & Company International.
Activity Drivers – Norway Norwegian activity levels are far less volatile than those of
Norwegian drilling activity has been steadily increasing over
the U.K. due to greater participation of government in the oil
the last decade. Average annual rig demand has grown from
and gas sector. The Norwegian Government retains stakes in
the low-teens to peak at 23 rigs in 2001 before slipping back
major operators Statoil (82%) and Norsk Hydro (44%) and is
to 19 in the last two years. Monthly demand reached a peak
also the largest direct owner of Norwegian oil and gas
of 25 rigs in late 2000 and early 2001. This increase in
resources (approximately 30% of reserves and production)
activity has been driven by Statoil and Norsk Hydro, the two
through Petoro (a wholly owned state company managing the
largest operators in Norway whom account for almost 55% of
SDFI - State’s Direct Financial Interest).
the wells drilled offshore.
Norwegian Rig Count Vs. Brent Oil Price 30
Norwegian Wells Drilled (1982-2003) 35
200
Rig Demand 30
Rig demand trend line.
20
25
15
20
10
15
5
10
0
5
160 Brent Oil Price ($ / bbl)
Norwegian Rig Demand
180
Oil Price (RH Scale)
25
Exploration Appraisal
140
Development 120 100 80 60 40 20
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Sources: BHI Rig Count and Simmons & Company International.
0 1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Sources: Norwegian Petroleum Directorate (NPD).
SIMMONS & COMPANY INTERNATIONAL
9
Activity Drivers – Norway (continued)
The two Norwegian majors drilled 50% more wells in
Average discovery sizes in Norway have fallen from 100mm
2000-2001 than in the preceding two years (an additional 120
boe per discovery well before 1993 to under 50mm boe over
wells) and have subsequently reduced activity. The timing of
the last three years. Given the dominance of major oil
this peak activity level in winter months is quite unusual but
companies in Norway, it is not surprising that these
coincides with Statoil’s initial public offering in June 2001.
companies are now focusing their exploration efforts
Norsk Hydro’s activity was driven by both exploration and
elsewhere. Future resource potential in Norway is fairly
development drilling, including significant activity on the
evenly split between the North Sea, Norwegian Sea and
large Troll and Oseberg fields.
Barents Sea although the Barents and Norwegian Sea are much less mature and are likely to be more attractive to oil
Aside from the large domestic oil companies who dominate
companies. The North Sea sector is prolific but relatively
Norway, it is the international integrated oil companies that
mature with fields in this area having produced around 92%
make up the balance of activity. It should therefore be
of total Norwegian oil and gas production to date.
remembered that Norway is a highly concentrated market with few smaller players (note Saga Petroleum was acquired
Norwegian Oil & Gas Resource Maturity By Region
by Norsk Hydro and Statoil in 1999).
35
Operator
Type Of Well By Operator E&A Development Total
Statoil Norsk Hydro ConocoPhillips BP ExxonMobil Saga Total Shell Other Total
26% 19% 9% 9% 10% 10% 7% 6% 4% 100%
33% 25% 18% 8% 8% 4% 4% 1% 0% 100%
31% 23% 15% 9% 8% 6% 5% 3% 1% 100%
1,184
2,355
3,539
# Wells
Oil & Gas Resource (Billion boe)
30
Norwegian Offshore Wells By Operator (1966-2003)
Barents Sea Norwegian Sea North Sea
25
20
15
10
5
0 Produced
Discovered
Undiscovered
Sources: NPD and Simmons & Company International.
Norwegian North Sea
Sources: NPD and Simmons & Company International.
The Norwegian North Sea is relatively mature (and closer to The lack of smaller players in Norway has been a cause of
the U.K. analogy) having been the primary source of
concern for Norwegian authorities as exploration and
Norway’s exploration, development and production over the
appraisal activity declined from approximately 50 wells per
last 30 years.
year in the 1990’s to roughly 20 to 25 wells per year in 2002 and 2003. This situation is now being addressed with a few
Norwegian North Sea Total Oil & Gas Resource Base
smaller companies taking interests in Norway and being actively encouraged by the Government. (Norway is in the
Discovered 21.7bn boe
Oil 4.4bn boe
fortunate position of being less mature than the U.K. and can therefore follow U.K. initiatives to stimulate activity where appropriate – such as attracting smaller E&P companies to
Undiscovered 7.5bn boe
maximize recovery of smaller reservoirs or fields reaching the tail-end of production). Examples of this include Talisman’s recent acquisition of the Gyda field from BP, and the emergence of a fledgling E&P sector for example, Pertra.
Produced 20.0bn boe
Gas 3.1bn boe
Sources: NPD and Simmons & Company International.
10
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – Norway (continued)
Of the total recoverable resource base, estimated at 50bn boe,
Unfortunately the Norwegian Government has decided these
around 40% has been produced to date while only 15%, or
areas are too environmentally sensitive to be open to oil and
7.5bn boe, remains to be discovered. Future discoveries are
gas activity. Two petroleum licenses in Nordland VI had
likely to be much smaller in size than the Statfjord, Gullfaks,
been awarded in 1996 but activity has been suspended (one
Oseberg and Ekofisk fields that have been the backbone of
well drilled with no discovery). The most recent 18th
production in this area. Average resource size per discovery
licensing round offered 95 blocks for oil and gas activity but
well has declined from 82mm boe in the early 1990’s to
Nordland VI remains closed for the time being. Therefore
around 10mm boe in the last three years. Activity in this
activity will focus on improved recovery from existing fields
region will therefore be about managing the decline and
and the development of Ormen Lange. Exploration activity
encouraging near-field exploration and development. A
has averaged around 6 ‘wildcat’ wells per year and any future
significant increase in drilling activity over the medium-term
increase will depend on access to acreage.
is therefore unlikely in this region of the Norwegian shelf. Barents Sea Norwegian Sea The Barents Sea remains an untapped resource for Norway. Production from the Norwegian Sea began in 1993 and
Exploration activity has been sporadic. A total of 39
makes up the remaining 8% (~2bn boe) of Norwegian
production licenses have been granted and since the first well
production to date. Key fields in this area include Heidrun,
spudded in 1980, a total of 61 exploration wells have been
Draugen, Norne and Njord with future developments
drilled, including eight in 2001 and 2002. Interest amongst
dominated by the Ormen Lange gas field (2.5bn boe).
oil companies had been muted but the recent approval of the Snohvit LNG development (1.3bn boe), developments in the
Norwegian Sea Total Oil & Gas Resource Base
Russian sector of the Barents Sea (Prirazlomnoye oil field development) and a number of medium sized finds has reignited interest.
Undiscovered 7.2bn boe Discovered 9.5bn boe
Barents Sea Total Oil & Gas Resource Base
Gas 4.7bn boe
Oil 2.5bn boe
Produced 1.8bn boe
Gas 3.4bn boe Discovered 1.4bn boe
Undiscovered 5.9bn boe
Sources: NPD and Simmons & Company International. Oil 2.5bn boe
The area is less prolific than the North Sea with an estimated resource base of 18.5bn boe. Costs are also generally higher in the Norwegian Sea due to high pressure high temperature
Sources: NPD and Simmons & Company International.
(HPHT) reservoirs, deeper waters, remoteness from markets and sensitivity to environmental concerns. However, this
Total resources are estimated at 7.4bn boe with no production
area is much less mature then the North Sea with only 10%
to date and around 81% still estimated as undiscovered. The
of reserves already produced and 39% as yet undiscovered.
recent 18th licensing round included permissions to resume
Of the projected 7.2bn boe of undiscovered resources, the
operations on a number of blocks in this area which had been
majority is gas with the area designated Nordland VI and
suspended pending an environmental impact assessment. It
Nordland VII (off Lofoten Islands) deemed highly
now seems likely that three wells will be drilled on the
prospective.
acreage between autumn 2004 and spring 2005.
SIMMONS & COMPANY INTERNATIONAL
11
Activity Drivers – Norway (continued)
Looking ahead, Norway clearly has significant remaining resource potential. In addition, the Government is concerned
Norwegian Future Field Development Projects 2,500
about current exploration activity levels and is taking steps to Norway a more attractive investment opportunity for smaller E&P companies, opening up more acreage and showing flexibility in the fiscal regime. Ho wever, as Statoil and Norsk Hydro endeavor to become more international oil and gas companies, competition for funds may mean that Norway may no longer be able to rely on these companies to drive activity to the same degree as in the past.
2007
2,000 Gas Oil
1,500
2006
1,000
500
2004 2005
No Set Development Plan / Schedule
0 Or m en La ng e Sn Kv ohv ite it bjo rn Kr ist in Ty S rih k an arv sS o La r vr an s Gj oa Id SV un Ka olv m e ele on Go lia t De lta Va Gek rg ko So uth St ae Da r gn 25 y /5 -5 25 Trym /11 -1 6 Ka pp a Ga m Fr m ej Al a Ve a ph s a t Co ok
encourage this going forward. These steps include making
Sources: NPD and Simmons & Company International.
From a resource base perspective, the Barents Sea and acreage around the Lofoten Islands are highly prospective.
The Snohvit field will initially be produced via six wells plus
The Norwegian Petroleum Directorate estimates that
a CO2 injector to be drilled in 2004-05. A further two wells
undiscovered resources in this area could reach 7.6bn boe or
will be drilled in 2011. In addition, the Albatross reservoir
37% of the Norwegian total. It is therefore disappointing that
will be tied in using four wells, three of which will be drilled
the area around Lofotens remains closed to oil and gas
in 2005-06 with the final well scheduled for 2014. The
activities. However, the recent opening of the Barents Sea
Askeladd reservoir will not be tied in until 2014-15 when
southern area is welcome and will likely result in at least
eight wells are planned. Further, the Government has
three wells being drilled between autumn 2004 and spring
allowed exploration activity around Snohvit to continue and
2005. Success with these wells and development of Snohvit
we would expect further drilling to be done in order to
and (potentially) Goliath discoveries could help spark further
improve the economics of the Snohvit field. Ormen Lange
drilling in the area. In addition, resolution of the disputed
will be developed via 20 to 24 wells with drilling
Barents Sea boundary between Norway and Russia may help
commencing in early 2004.
open up further acreage. Similarly, activity on the Russian side of the boundary could offer further insights into the
18 th Licensing Round
plays geology and prospectivity. The Norwegian Government recently announced that 95 Future Developments
blocks (or part blocks) would be available for applications in the 18th biannual licensing round. This is a significant
Norwegian projects with development approval (or where
increase (200-300%) on acreage available in the prior three
approval is expected within the next four years) will access
rounds. This reflects the Government’s concern at current
around 5.9bn boe of reserves (22% oil / 78% gas). These 24
activity levels and a desire to increase activities in the near
developments are dominated by the massive Ormen Lange
future. Licenses have an initial term of six years.
and Snohvit gas projects, due on stream in 2007 and 2006
Applications will be submitted by March 15, 2004 and
respectively, which account for 3.4bn boe of reserves (57%
awards made in Q2’04.
of new development total). Excluding these projects the median reserve size is 56mm boe with only seven developments of the remaining 22 containing estimated reserves above 100mm boe.
12
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – Netherlands The Netherlands is an important component of the North Sea
As discussed, oil production is a relatively small part of
drilling market. In 2003, rig demand reached eight rig years
Dutch hydrocarbon production although the recent Hanze
with peak activity of 10 units in late September. The
field development, operated by Petro-Canada, produced
Netherlands is a jack-up market and has been very important
26mboed in 2002.
for drilling contractors with a strong jack-up presence (i.e. Noble, Ensco and Global Santa Fe).
2002 Dutch Offshore Gas Production (100% = 2.6bcfd)
Background
Other 10%
GDF 12%
The Netherlands produced approximately 1.2mmboed in
NAM 41%
2002. Production is dominated by gas (96%) with oil production a relatively minor 50mboed. Gas production is split 60:40 between onshore fields (4.3bcfd / 710mb oed) and
Wintershall 13%
the continental shelf (2.6bcfd / 430mboed). Dutch production is dominated by the onshore Groningen field, discovered in 1959, which produced 3bcfd (500mboed) or 42% of total production in 2002 but has been on the decline
Total 24%
Sources: SODM, Simmons & Company International.
in recent years. Future Developments Netherlands Oil & Gas Production (1996-2003)
Wintershall and GdF will play a disproportionately important
1,600
Oil
Daily Production (mboed)
1,400
role in future Netherlands activity. Both companies are
Gas
1,200
seeking to grow production with the Netherlands playing an
1,000
important part in their portfolios. This is borne out by recent
800
tender activity with Wintershall seeking information on three to four jack-ups for 1 well plus option programs commencing
600
early 2004. With additional programs likely from GdF,
400
NAM and Total, 2004 should see a similar activity levels to
200 0 1996
2003. 1997
1998
1999
2000
2001
2002
Sources: BP Statistical Review, SODM, Simmons & Company Intl.
NAM, a joint venture company between Shell and ExxonMobil, is the dominant producer in the Netherlands. The company produces around 800mboed of gas (67% of total production) primarily through the Groningen field and other smaller onshore fields. Offshore, NAM is less dominant, producing around 175mboed, or 40% of offshore production. Other important offshore operators include Total (operate 104mboed) and Wintershall (60mboed) which has significantly increased its position through the 2002 acquisition of Clyde Netherlands. Gaz de France (GdF) is also an important player operating ~50mboed offshore Netherlands.
SIMMONS & COMPANY INTERNATIONAL
13
Activity Drivers – Denmark Denmark is often overlooked in the North Sea picture but is
Danish Reserve Estimates
an important part of the North Sea rig market. In 2003 an average of eight jack-ups (0 floaters) were fully utilized in
Producing 1.8bn boe Planned 0.1bn boe
Denmark (27% of North Sea jack-up demand). Activity in
Oil 0.5bn boe
Denmark has been on the increase in recent years with nine exploration and appraisal wells and 27 development wells
Possible 0.7bn boe
drilled in 2002 with a similar level anticipated in 2003 and 2004. Produced 1.9bn boe
Background Danish production of oil and gas totaled 503mboed in 2002, a
Gas 0.2bn boe
Sources: DEA, Simmons & Company International.
new record. Production volumes increased rapidly in the 1980’s with the development of the Dan, Gorm, Skjold and
Operations in Denmark are dominated by the DUC (Danish
Tyra fields which account for 77% of oil and 65% of gas
Underground Consortium) formed in 1962 to explore for oil
produced in Denmark to date. These four fields, particularly
and gas in Denmark. Maersk Oil & Gas, a subsidiary of AP
Dan, Gorm and Tyra remain the backbone of Danish
Moller, operates on behalf of DUC partners (Maersk 39%,
production representing 54% of oil and 37% of gas
Shell 46%, ChevronTexaco 15%). Maersk Oil & Gas
production in 2002.
operates 16 fields in Denmark with DONG (state-owned E&P company) and Amerada Hess making up the remainder.
Danish Oil & Gas Production (mboed) E&A Wells By Operator (1966-2003)
600
Danish Exploration & Appraisal Wells By Operator Since 1966 Since 2000 % Since 2000 Maersk Oil & Gas 78 31 57% DONG 11 11 20% Amerada Hess 8 3 6% Statoil 12 2 4% ConocoPhillips 4 2 4% ChevronTexaco 81 0 0% Other 25 5 9% Total 219 54 100% Sources: DEA, Simmons & Company International.
Oil & Gas Production (mboed)
500
400
Gas Oil
300
200
100
20 02
20 00
19 98
19 96
19 94
19 92
19 90
19 88
19 86
19 84
19 82
19 80
19 78
19 76
19 74
19 72
0
Sources: DEA, Simmons & Company International.
Unsurprisingly, it is these companies that dominate drilling in Denmark, accounting for 83% of E&A wells drilled over the
In total there are 20 producing fields in Denmark with
last four years. It is interesting to note the more pro -active
reserves heavily concentrated in the largest six fields (1.4bn
participation of DONG, the state-owned company in
boe versus 400mm boe in remaining 14). Total remaining
operations. Previously, DONG held 20% interests in
reserves in Denmark are estimated at 2.6bn boe (69% oil)
production licenses as part of the Danish fiscal regime
which includes 1.8bn boe from currently producing or
(managing the state’s participation in hydrocarbon licenses).
approved fields and 800mm boe from currently planned or
Now DONG is operator of three producing fields and several
possible developments.
exploration licenses and has an objective of further developing small fields in Denmark.
14
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – Denmark (continued)
Future Developments
In addition to new fields being brought on stream further development work is also likely on existing fields and
Fields scheduled to be brought on stream over the next five
particularly Dan and Halfdan. The Danish authorities expect
years are generally smaller in nature than those developed in
production to grow in 2004, driven by recent field
recent years (two largest recent developments (Halfdan
development activity, before declining in 2005. Drilling
(540mm boe) and South Arne (260mm boe) fields brought on
activity is expected to remain constant in 2004 before
stream in 1999).
declining in 2005 without further exploration success.
Danish Future Field Developments Future Field Developments Fields Adda Boje Area Alma Elly Amalie Freja Total
Start Up 2005 2005 2007 2007 -
Oil (mmboe) 6 6 6 6 13 6 44
Reserves Gas (bcf) 0 0 38 189 113 0 340
Total (mmboe) 6 6 13 38 32 6 101
Sources: DEA, Simmons & Company International.
North Sea Drilling Contractors North Sea Jack-Up Fleet By Contractor – Dec 17 2003
Most major drilling contractors have a presence in the North
SME NO RDC 3% 3%
Sea market in addition to a number of smaller “domestic”
NE 25%
players. In addition, some contractors choose to deploy only GSF 22%
jack-up or floater rigs in this market. Jack-Ups The North Sea jack-up market has four major players (seven to eight rigs per contractor) and two companies with one rig a
Maersk 25%
ESV 22%
piece. Noble Corp and Maersk have the largest jack-up fleets in the North Sea (eight units each) closely followed by Ensco
Sources: Platts, OneOffshore, Simmons & Company International.
and Global Santa Fe (seven units each). Maersk and Ensco enjoy particularly strong positions in Denmark. In the first
North Sea Jack-Ups By Status/Contractor – Dec 17 2003 9
Maersk E&P subsidiary while Ensco has been successful in
8
winning work with DONG. Historically, Noble has had a
7
strong position in the Netherlands and this continues to be an
6
important market for it alongside the U.K. Global Santa Fe has a number of units working in the Netherlands but the U.K. remains its primary market for jack-ups. The Smedvig and Rowan jack-ups remain on long-term charters in Norway and the U.K. respectively.
North Sea Fleet
instance, Maersk is the obvious drilling contractor for the
Available Working
5 4 3 2 1 0 NE
Maersk
ESV
GSF
SME NO
RDC
Sources: Platts, OneOffshore, Simmons & Company International.
SIMMONS & COMPANY INTERNATIONAL
15
North Sea Drilling Contractors (continued)
Floaters
North Sea Floaters By Status/Contractor – Dec 17 2003 18 16
in the North Sea (42% of the total), only eight of which are
14
currently working. Transocean is focused on the northern
12
sector of the U.K. and Norwegian markets which have suffered most from reduced activity in recent years. A
North Sea Fleet
The floater market is dominated by Transocean with 17 units
Available Working
10 8
number of contractors have two to four semis in this market
6
including Global Santa Fe, Diamond and more regional
4
players such as Fred Olsen (Norway), Odfje ll (Norway),
2
Smedvig (Norway) and Stena.
0 RIG
GSF
DO
FOE NO
Odfjell
Stena
SME NO
NE
SPM IM Petrolia
Sources: Platts, OneOffshore, Simmons & Company International.
North Sea Floater Fleet By Contractor – Dec 17 2003
SME NO 5%
N E SPM IM 3% 3%
Petrolia 3%
Stena 8% RIG 42%
Odfjell 8%
FOE NO 10%
DO 9%
GSF 9%
Sources: Platts, OneOffshore, Simmons & Company International.
Conclusions North Sea rig demand will likely remain essentially flat in
due to the overhang of cold-stacked units in this market. We
2004 at ~ 57 rig years of demand. However, utilization
would expect to see day rates improve from current cash cost
should improve, by approximately 15% to 90% overall, due
levels.
to the reduction in available fleet from 76 units in early 2003 to 64 units in 2004 (excluding 10 cold stacked units).
In the medium term there are a number of activity drivers that could drive an improvement in North Sea rig demand. These
The jack-up market will remain healthy in 2004 with
include greater participation of independent oil companies,
practically full utilization expected, an improvement of ~10%
the 18th and 21st licensing rounds in Norway and the U.K.,
over 2003 due to reduced supply and potential for increased
incentives from Government, the opening of acreage in
demand. The potential for day rate appreciation exists,
Norway, the continued success of companies aggressively
particularly during peak activity in Q3-Q4.
pursuing opportunities in the North Sea (e.g. Apache, EnCana) and continued strong commodity prices.
On current expectations, the North Sea floater market will experience a significant increase in utilization during 2004, to
In the longer term, the North Sea is maturing and will require
79% from 64% in 2003. This is driven by a reduction in the
constant improvements in cost and productivity to compete
available fleet from 42 units to 32. However, the potential
for capital.
for significant day rate appreciation is limited in our view
16
SIMMONS & COMPANY INTERNATIONAL
Analyst Certification and Disclaimer Analyst Certification: I, Ruairidh Stewart, prepared this report and hereby certify that the views expressed in it to the best of my knowledge accurately reflect my personal views about the subject compan(ies) and its (their) securities; and that, I have not been, am not, and will not be receiving direct or indirect compensation in exchange for expressing the specific recommendation(s) or views in this research report. Disclosure: This report is based on information obtained from sources which Simmons & Company International believes to be reliable, but Simmons & Company International has not verified the information and does not represent or warrant its accuracy or completeness. The opinions, ratings and estimates contained in the report represent the views of Simmons & Company International as of the date of the report, and may be subject to change without prior notice. For detailed rating information, go to http://publicdisclosure.simmonsco-intl.com. Research analysts compensation is based upon (among other things) the firm's general investment banking revenues. Simmons & Company International may seek compensation for investment banking services from NE, ESV, GSF, SME.OL, RDC, RIG, DO, SPMI.MI and other companies for which research coverage is provided. The firm would expect to receive compensation for any such services. One of the analysts, or a member of the analyst's household, responsible for the preparation/supervision of this report has a Long Stock position in GSF. Simmons & Company International has received compensation from ESV for investment banking services in the past 12 months. Simmons & Company International has received compensation from GSF for investment banking services in the past 12 months. Simmons & Company International has received compensation from SME.OL for investment banking services in the past 12 months. Simmons & Company International will not be responsible for the consequence of reliance upon any opinion or statement contained in this research report. This report is confidential and may not be reproduced in whole or in part without the prior written permission of Simmons & Company International. Please note: All electronic mail sent to or received from this address will be archived by Simmons & Company International's electronic mail system and is subject to review by someone other than the recipient. Nothing in the research report is, or should be relied upon as, a promise or a forecast and no representation or warranty is given as to the accuracy, achievement or reasonableness of any future projection, estimate, forecast or statement about future prospects. The value of securities can go down as well as up and past performance is not a guide to future performance. The research report is directed only at and may only be communicated to persons outside the EEA; persons who have professional experience in matters relating to investments who fall within the definition of investment professionals in Article 19(5) Financial Services and Markets Act (Financial Promotion) Order 2001 (as amended) (“FPO”); persons who fall within Article 49(2)(a) to (d) FPO (high net worth companies, unincorporated associations etc.) or persons who are otherwise market counterparties or intermediate customers in accordance with the FSA Handbook of Rules and Guidance (“relevant persons”). The research report must not be acted on or relied upon by any persons who receive it within the EEA who are not relevant persons. Simmons & Company International does not treat the recipient of the research report as its customer and it is not, therefore, responsible for providing such recipient with legal or regulatory protections. The research report is provided solely for information purposes. It does not constitute an offer or recommendation to sell or an invitation to offer to buy an interest in the subject of the research report. The research report is not intended to be an inducement to enter into a contract nor is it intended to form the basis of an investment decision, and it should not be treated as if it were or relied upon in any way. Receipt of the research report does not constitute the giving of investment advice by Simmons & Company International. Simmons & Company International is registered with the SEC and is a member of NASD and SIPC. Simmons & Company International Limited is authorised and regulated by the Financial Services Authority to undertake designated investment business in the United Kingdom.
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Oil Service Industry Research January 8, 2004
North Sea Drilling Outlook: Future Looking Brighter? The North Sea offshore drilling market has suffered from weakening demand, oversupply of units and a resultant fall in day rates over the last three years. Our analysis suggests that fleet utilization will improve, potentially significantly (15%), in 2004. However, this improvement is a function of reduced supply rather than increased demand and we therefore believe significant increases in day rates are unlikely. Notwithstanding these comments, the North Sea jack-up rig market remains significantly healthier than the floater market and continued strong utilization provides the opportunity for attractive day rates during peak activity.
Ruairidh (Rory) Stewart +44 1224 202328 [email protected]
*Important disclosures appear at the end of this report.
North Sea Rig Market Outlook
Pros •
Cons Based on rigs currently contracted and visible
•
The improvement in utilization is being driven by
tenders, demand appears essentially flat with 2003
reduced supply rather than increased demand, thus
but supply is reduced by 12 units.
day rate gains are likely to come in small increments over time.
•
Utilization could improve by 15% to roughly 80% for floaters and by 12% to essentially 100% for
•
The North Sea is still dominated by major oil
jack-up rigs increasing the possibility for day rate
companies focused on investment opportunities
appreciation for jack-ups.
outside the North Sea. The North Sea ranks poorly in global competition for funds.
•
It is difficult for units to return to North Sea without longer term contract / high day rates, thus we do not
•
expect supply to expand meaningfully.
The pace of majors divesting quality assets is likely to remain slow as the North Sea remains an important source of cash for deployment elsewhere.
•
From an E&P perspective, strong commodity prices make the North Sea a highly attractive investment
•
opportunity.
The North Sea is maturing and the average development size is declining. This secular trend is uninspiring for future drilling activity.
•
st
The 21 Licensing Round in the U.K. (July 2003) awarded 88 licenses on which prospects could be
•
developed for drilling during 2004.
The high cost of drilling / development is a barrier to smaller companies wishing to enter the North Sea E&P sector.
•
Recent U.K. Government actions have lowered barriers to exploration in the U.K. o
100% capital allowance
o
Exploration supplement for new entrants
o
Promote licenses
o
Action on access to infrastructure
•
Recent exploration results in Norway / Faroes / West of Shetland have been disappointing.
•
Recent changes to U.K. fiscal policy are discouraging for the industry as a whole. There is fresh disappointment that capital allowances for
•
Activity is projected to increase on those assets
exploration were not increased to 125-150%
divested by the majors (e.g. Apache Forties, CNR
following recent consultation process.
Ninian). • •
Norway is similarly encouraging as the government
are generally more spasmodic and related to
has reopened activity in the Barents Sea and offered
commodity prices. This adds uncertainty to the
th
significant acreage in the 18 Licensing Round. •
Relative to majors, independents activity programs
outlook for drilling contractors.
Cooperation agreement between U.K. and Norway opens up potential development opportunities along the median line between the two countries.
•
Large scale developments including Snohvit, Ormen Lange, Buzzard, Clair and Goldeneye will require development drilling programs during 2004-2006.
2
SIMMONS & COMPANY INTERNATIONAL
North Sea Market Context Over the last twenty years, the North Sea has on average represented approximately 23% of international offshore mobile rig activity. North Sea demand has been on a downward trend since 1985 driven by weaker U.K. activity levels. Norwegian activity has increased in recent years but this has been insufficient to offset declines in the U.K., which now accounts for under 50% of total North Sea rig demand. North Sea rig demand peaked in 1985 at an average of 90
U.K. activity levels have historically dominated the North
rigs (peak month July 1985 at 96 rigs). Since that time,
Sea market (65% to 70% of rig demand), but this is no longer
demand has fluctuated widely but has remained on a
the case with the U.K. representing 42% of North Sea
downward trend. External influences such as commodity
activity in 2003. While rig demand in Norway has been
prices are an important driver of North Sea activity, reflected
increasing in recent years, this has been insufficient to offset
in record low drilling demand of 28 rigs in October 1999
the overall decline in North Sea demand due to weakness in
following Brent crude hitting $10 barrel. Activity has since
U.K. activity levels. In 2003, Norway and the U.K. each had
recovered but remains well below 1985 levels. This is
average rig demand of 19 units, equal to 42% of total North
particularly disappointing given the strong commodity prices
Sea rig demand. The remaining 16% of demand was made
that have prevailed since 1999 which the industry has not
up equally by the Netherlands and Denmark which have
converted into higher activity levels. This disconnect can be
remained important activity centres, particularly for the jack-
attributed to the relative unattractiveness of new investment
up market.
opportunities in the North Sea versus other regions, at least for the major oil companies who dominate the basin. North Sea Offshore Rig Demand By Country (Average Annual Rig Demand And % Of Total) 100
100% Denmark
90
Norway
70
U.K.
Percentage of North Sea Rig Demand
Annual Average Rig Demand
Netherlands 80
60 50 40 30 20
80%
60%
40%
Denmark Netherlands Norway U.K.
20%
10 0 1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
0% 1982
2002
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Sources: Baker Hughes Rig Count and Simmons & Company International.
U.K. Rig Count Vs. Brent Oil Price
U.K. Wells Drilled (1990-Q3 2003)
70
35
300
30
250
50
25
200
40
20
30
15
20
10
U.K. Wells Drilled
U.K. Rig Demand
Oil Price (RH Scale)
Brent Oil Price ($ / bbl)
Rig Demand 60
Exploration Appraisal Development
150
100
50
U.K. rig demand trend line.
1986
1988
1990
1992
1994
1996
1998
2000
20 01
20 00
19 99
19 98
19 97
19 96
19 95
19 94
2002
20 02 20 03 To Q3
1984
19 93
0 1982
19 92
0
0 19 91
5
19 90
10
Sources: BHI Rig Count, Bloomberg, U.K. Department of Trade & Industry (DTI) and Simmons & Company International.
SIMMONS & COMPANY INTERNATIONAL
3
North Sea Rig Market Outlook For 2004 We believe the North Sea rig market will realize higher fleet
In response to these tighter conditions, jack-up day rates have
utilization in 2004 compared to 2003. While this is primarily
been more resilient than semi day rates but are still below
a supply led phenomenon, there are a number of positive
peak 2001 levels. This corresponds to a global softening in
demand catalysts that could drive an improved market in the
market conditions and the overhang from semis in the
medium term. These factors include i) major oil companies
market.
divesting assets; ii) drilling on acreage from recent U.K. licensing round and; iii) opening of the Barents Sea southern
North Sea Standard Jack-up Day Rates
area. These issues are discussed in more depth under the
$100
specific country sections. We believe day rates should appreciate to 2001 levels ($80k / day for standard jack-ups, $90k / day for standard semis). In short, the market looks to be “OK” in 2004 but without a global improvement in demand there will, on the whole, be adequate supply to
Day Rates ($'000 / Day)
$80
improve incrementally during 2004 but are unlikely to
$60
UK
$40
Netherlands
$20
satisfy demand and curtail opportunities for significant day rate improvements.
$0 Jan'01
Apr
Jul
Oct
Jan'02
Apr
Jul
Oct
Jan'03
Apr
July
Oct
Jack-ups
Sources: Platts, Simmons & Company International.
The North Sea jack-up market is much tighter than the floater
Looking ahead into 2004 there is currently 14.3 rig years of
market and we would expect this to continue through 2004.
work already contracted providing a base utilization of 45%.
Jack-up demand is not as concentrated in the U.K. and
This is down slightly year on year from 18.4 rig years of
Norway as the floater market (U.K. 36% of 2003 demand,
demand contracted 12 months ago for 2003 (54% utilization).
Netherlands 27%, Denmark 27% and Norway 9%) and the
However, in addition to the units currently contracted, we
current fleet is comprised of 32 units with 30 currently
also have visibility on tenders totaling 10.2 rig years of
working (94% utilization). While in the very short-term the
demand in 2004 (peak of 14 units in July and September).
market is likely oversupplied by one to two units, these can
This is significantly higher than tenders in the market 12
be quickly consumed as activity picks up in the summer
months ago for 2003 and helps compensate for the lower
months leading to full utilization. Since early 2003, a net two
levels of forward activity currently contracted.
units have left the North Sea further improving the prospects of a tight demand / supply balance.
Snapshot Forward 1 Year Utilization ‘03 vs. ‘04 100% 90%
North Sea Jack-up Rig Disposition 2003
80%
100% Rig Utilization
90% 80% 70% 60%
60% 50% 40% 30%
50%
20%
40%
10%
Available 30%
0%
Working
1
20%
6
11
16
21
26
36
41
46
Sources: Platts, OneOffshore, Simmons & Company International. Feb-03
Apr-03
May-03
Jul-03
Aug-03
Sep-03
Nov-03
Dec-03
Sources: Platts, Simmons & Company International.
4
31
Week
10% 0% Jan-03
Jack Up Fwd Util - 2003 Jack Up Fwd Util - 2004
70%
SIMMONS & COMPANY INTERNATIONAL
51
Rig Market Outlook For 2004 (continued)
Additional tenders will likely emerge as 2004 progresses and
This is particularly the case in the northern sector of the U.K.
it is notable that approximately 12.9 rig years of additional
North Sea and the Norwegian North Sea. There are currently
tenders came out during 2003 (although slightly over 5.5 rig
40 floaters in the North Sea fleet, with only 22 working (54%
years failed to progress to actual activity). Assuming a
utilization), 11 available and seven cold stacked. Current
similar level of tendering during 2004, demand could
demand of 22 units is similar to the 2002-2003 holiday
increase by two rig years driving utilization to essentially
period but the supply side of the equation has improved
100% and creating very tight conditions during peak
significantly since then. In late December 2002 there were
activity in Q3’04.
45 floaters in the North Sea, only three of which were cold stacked. Since that time, five units have left the North Sea
North Sea Jack-Up Market Summary 2003-2004E Fleet At Start
North Sea Jack-Up Market 2003 2004 34.0 32.0
Contracted Demand At Start Visible Tenders At Start Tenders During Year Total Potential Demand Actual Demand
18.4 4.1 12.9 35.4
Change -2.0
14.3 10.2 12.9 37.4
-4.1 6.1 0.0 2.0
29.9
31.9
2.0
Tenders Not Progressed
5.5
5.5
0.0
Utilization (based on Jan fleet)
88%
100%
12%
while an additional four units have been cold stacked. We also anticipate a further unit leaving the North Sea within the next month. Therefore, the readily available floater rig count will have been reduced by 10 units in 13 months – the major positive influence in this market. North Sea Floater Fleet Disposition 2003 100%
80%
60%
Sources: OneOffshore, Simmons & Company International.
40%
Available Cold Stacked
Looking at tenders currently visible, companies such as
Working
Venture Production, Petro-Canada, ATP and DNO do not
20%
have any visible tenders in the market at present. However, 0% Jan-03
these companies do have emerging drilling programs. For example, Venture Production will likely drill four to five
Feb-03
Apr-03
May-03
Jul-03
Aug-03
Sep-03
Nov-03
Dec-03
Sources: Platts, Simmons & Company International.
wells in 2004 plus several well workovers which could add between 0.5-0.8 rig years of demand. If our projections
Due to excess capacity, day rates have moved sharply
prove overly optimistic, a repeat of 2003 average demand of
downwards for North Sea semi-submersibles (semis) over the
29.9 rigs equates to utilization of 93% in 2004 - enough to
last three years. At current levels, day rates offer a thin
keep the jack-up market in good health during the year.
margin above cash costs - this explains contractor’s motivation to cold stack rigs.
Increased utilization will lead to improved day rates for the jack-up fleet. However, we do not anticipate a surge in rates,
North Sea Standard Semi Day Rates
but rather incremental improvement. In our opinion, the
$160
global rig surplus and the overhang in the North Sea floater
$140
market will serve to dampen rate potential during 2004.
The floating rig market will likely remain oversupplied throughout 2004. The North Sea floaters market is driven by
Day Rates ($'000 / Day)
Floaters
UK $120 Norway $100
$80
$60
$40
U.K. and Norwegian drilling activity (50% & 40% of 2003 demand respectively) and has suffered from declining demand in both areas.
$20 Jan'01
Apr
Jul
Oct
Jan'02
Apr
Jul
Oct
Jan'03
Apr
July
Oct
Sources: Platts, Simmons & Company International.
SIMMONS & COMPANY INTERNATIONAL
5
Rig Market Outlook For 2004 (continued)
Many of the available units are being marketed globally, and
Assuming a similar pattern for new tenders (and failure of
once a rig leaves the North Sea it is unlikely to return without
some tenders to progress to actual work) we anticipate
the incentive of a significant contract term or increased day
slightly lower floater demand of 25.4 rig years in 2004.
rates. Additionally, several rigs leaving the North Sea will
However, this would result in much improved utilization - to
need upgrades to come back into the market, having been
an average of nearly 80% due to the reduction in fleet size.
given exemptions from regulations introduced while the unit was working in the North Sea (i.e. accommodation
North Sea Floater Market Summary 2003-2004E
standards). This will act as a further deterrent for units to reenter the market.
Fleet At Start Cold Stacked Available Fleet
Looking ahead into 2004, floaters currently contracted total
North Sea Floater Market 2003 2004E 45.0 39.0 3.0 7.0 42.0 32.0
Change -6.0 4.0 -10.0
Contracted Demand At Start Visible Tenders At Start Tenders During Year Total Potential Demand
13.7 7.5 11.8 33.0
13.3 6.2 11.8 31.3
-0.4 -1.3 0.0 -1.7
Taking the same snapshot 12 months ago for 2003 would
Actual Demand
27.0
25.4
-1.7
have yielded a similar contracted demand level (13.7 rig
Tenders Not Progressed
5.9
5.9
0.0
Utilization (based on Jan fleet)
64%
79%
15%
13.3 rig years of demand and provide contracted utilization of roughly 34% as it stands today. Excluding cold stacked units, current average utilization is 41% for next year.
years) but average contracted utilization of 33% due to the greater number of units in the market (excluding cold stacked
Sources: OneOffshore, Simmons & Company International.
units). Overlaying 2003 demand with current fleet statistics Snapshot Forward 1 Year Utilization ‘03 vs. ‘04
highlights the potential improvement in utilization due to fleet rationalization.
70%
60%
Floater Fwd Util - 2003 Floater Fwd Util - 2004
2003 Floater Demand Versus 2004 Fleet
Rig Utilization
50% 100% 40% 80% 30% 60%
20%
10%
40% 1
6
11
16
21
26
31
36
41
46
Available Cold Stacked
51
Week
Sources: Platts, Simmons & Company International.
In short, fundamentals for the North Sea floater market have modestly improved due to a reduction in total fleet capacity and an increase in cold stacked rigs. Looking more closely at 2004, currently visible tenders provide an additional 6.2 rig years of demand (peak of 11 units in May’04) in addition to the 13.3 rig years already contracted. More tenders will emerge over the next 12 months. For example, in 2003 an additional 11.8 rig years of demand emerged during the year
Working 20%
0% Jan-04
Feb-04
Apr-04
May-04
Jun-04
Sep-04
Nov-04
Dec-04
Sources: OneOffshore, Platts, Simmons & Company International.
As a result, we envisage U.K. day rates improving but remaining relatively constrained (approximately $55-60k during the summer peak in activity) and well short of the $80-100k rates enjoyed during 2001.
(peaking at 21 units in August) from total tenders of 17.5 rig years (some tenders do not progress to actual activity). Just under five rig years of demand was generated by short-term camp aigns for independents.
6
Aug-04
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – U.K. As the U.K. North Sea matures as a hydrocarbon basin,
U.K. Government Actions
drilling activity has declined significantly due to less exploration and decreasing size of developments. One of the
The U.K. Government has stated it is committed to ensuring
key questions emerging from this analysis is the likelihood of
the maximum possible exploitation of oil and gas resources
any recovery in U.K. activity levels. This is a subject area
in the U.K. Within this broad aim are a number of specific
we have touched upon many times (see our reports on U.K.
initiatives to encourage new players into the North Sea.
issues from October 2001, May 2002 and February 2003) and
These include the fallow field initiative, infrastructure access
we do not wish to rehash that analysis here. However, key
(transportation and processing), cooperation with Norway,
factors to indicate improving fundamentals in the U.K. are i)
new licensing and adjustments to the fiscal regime.
transition of asset ownership from majors to independents, ii) government actions and iii) future field developments.
Fallow Fields
Transition Of Asset Ownership From Majors To
The fallow field initiative seeks to encourage activity on
Independents
licenses that have turned fallow, i.e. have had no activity (seismic, drilling etc.) for a number of years. In 2002, over
We have previously emphasized the impact smaller
200 blocks were identified as “fallow” and owners were
independent players could have in driving a renaissance for
instructed to “use it or lose it”. Since that time over 100
the U.K. industry – similar to the Gulf of Mexico in the mid
blocks have been taken out of the fallow category as 39 have
1990’s. However, after getting off to a fanfare start in 2003
been relinquished, 28 exploration and appraisal wells have
with BP selling Forties to Apache, asset disposals by major
been drilled, nine seismic surveys have been conducted and
oil companies have been relatively disappointing.
one block is producing. With a further 172 blocks estimated to turn fallow in 2003 the Government is hoping to accelerate
The impact of divestments when they occur and the
this initiative and force existing owners to invest or release
momentum offered by new players is evidenced by activity in
the acreage to those that will.
2003 and current plans. We estimate these smaller players (e.g. Venture Production, Apache, CNR, ATP, Ramco,
Access To Infrastructure
Pertra, EnCana etc.) brought an additional five to seven rig years of work into the market in 2003. Apache’s recent
Major oil companies dominate platform and pipeline
contract with Global Santa Fe’s Galaxy I and Galaxy III rigs
infrastructure. The issue of tariffs charged by the majors for
for drilling over the Forties Echo platform is another good
new developments being tied into their infrastructure has
example of an aggressive program being put together by new
been raised by many participants as a roadblock in
asset owners. Asset disposals by the major oil companies is
maximizing opportunities in the U.K. North Sea. Progress
good news for the drilling market but we remain concerned
has been made on this issue over the last few months. The
that divestment of reasonable quality properties will occur at
Department of Trade and Industry (DTI) expects tariffs
a slow pace. Such assets generate attractive cash flow at
(which in some circumstances have represented 45% of total
current commodity prices – very useful for companies
field costs) to come down in the future and has pressed
investing huge sums in less mature / higher growth potential
infrastructure owners to follow a code of practice, show
areas such as West Africa, deepwater Gulf of Mexico and the
processes are in place to set fair and reasonable tariffs, make
FSU. We therefore reiterate our belief that disposals will
tariffs more transparent and put in place a mechanism for the
continue but remain incremental in nature and that major oil
DTI to intervene in negotiations. These changes should
companies will continue to dominate the U.K. industry.
ensure that infrastructure owners do not take a disproportionate share of the rewards from new field developments.
SIMMONS & COMPANY INTERNATIONAL
7
Activity Drivers – U.K. (continued)
Cooperation With Norway
This last point will mean new entrants without a profit stream in the U.K. will be less disadvantaged due to their inability to
The recent agreement signed between the U.K. and Norway
absorb capital allowances in Year one. The industry had
not only paves the way for the giant Ormen Lange gas field
been pushing for an increase in exploration and appraisal
development, but also allows more flexible use of
capital allowances to 125% but the Government has decided
infrastructure on both sides of the median line. This will
the case for this has not been proven (a disappointment for
likely result in a life extension for U.K. infrastructure
the industry who had suggested this could increase
(processing / transporting Norwegian hydrocarbons) thereby
exploration drilling by two to three wells per annum).
extending the timeframe to exploit resources situated near infrastructure and will also help increase activity around the
Future Developments
median line between the U.K. and Norway. The outlook for new field developments in the U.K. is very New Licensing
mixed. Current forecasts from Deloitte & Touch suggest a total of 61 new field developments between now and 2008
The introduction of “Promote Licenses” in the U.K. 21
st
although it is likely that many scheduled in 2004 and 2005
licensing round (May 2003) lowers the threshold for
will slip. The economic reserves accessed by these
companies to win acreage in the U.K. The promote licenses
developments total 2.7bn boe (average reserve size is 44mm
charge lower acreage fees and companies do not have to pass
boe).
financial, technical and environmental competency tests that apply to traditional license. The license provides the holder
Future U.K. Field Developments
with a two year opportunity to assess and promote the prospectivity of the acreage before they need commit to drilling a well or displaying the financial, technical and environmental competencies to do so. Fifty-three such licenses were awarded in May 2003 and it is possible that the more serious license winners may be in a position to seek funding / partners to start drilling in mid-2004.
Start Date
Economic Reserves No. DevelopOil Total Average ments (mmbbls) Gas (bcf) (mmboe) (mmboe)
2004 2005 2006 2007 2008 Total
23 22 7 8 1 61
512 208 713 111 147 1,691
2,523 2,023 501 829 0 5,876
933 545 797 249 147 2,670
41 25 114 31 147 44
Sources: DTI, DTPS, Simmons & Company International.
Fiscal Regime The key developments over the next few years are EnCana In the April 2002 budget, the U.K. Chancellor introduced a
Buzzard, BP Clair and Shell Goldeneye. These three fields
10% corporation tax surcharge on profits from U.K. oil and
account for 945mm boe or 35% of the total from 61 future
gas extraction. At the same time 100% capital allowances
developments. Excluding these three larger fields, the
(amount of investment deductible for tax purposes in fiscal
average development size falls to 30mm boe. These smaller
year – in lieu of depreciation) were introduced to encourage
developments will generally be comprised of a subsea tie-
new investment. These changes were greeted with dismay by
back or unmanned platform utilizing existing infrastructure
the industry although our analysis suggested that companies
for processing and export. More importantly, in the context
who were investing in new developments were only
of this report, drilling requirements are generally minimal for
marginally negatively impacted (see May 2002 report).
such developments – perhaps two to three wells per
Since then the Government has abolished the 12.5% Royalty
development.
charged on pre 1982 fields and PRT on new field developments. Most recently, the Chancellor announced that 100% capital allowances will be carried forward with interest for investments in exploration.
8
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – U.K. (continued)
In contrast, the Buzzard development (~550mm boe) will be
On the exploration side, the leading drillers in 2003 were
comprised of three platforms and EnCana has a tender for
Kerr McGee and EnCana with six wells apiece. Into 2004
drilling 10 firm wells plus 20 option wells starting H2’05.
these two companies are expected to maintain that pace with
EnCana will also pursue exploration opportunities close to
Kerr McGee potentially drilling four to six wells in the
Buzzard to tie back discoveries and keep the platform fully
Central North Sea next year while EnCana is expected to drill
utilized. The BP Clair development (Phase I ~ 270mm boe)
five exploration and appraisal wells.
will have 15 producing wells and eight water injection wells while Shell Goldeneye will produce through five production
Exploration activity beyond 2004-05 will depend on the
wells which are being drilled currently.
success achieved by those companies now aggressively pursuing opportunities, such as EnCana and Kerr McGee. Failure to follow up Buzzard with other meaningful
U.K. Total Oil & Gas Resource Base
discoveries will inevitably result in lower exploration activity Discovered 18.9bn boe
in the longer term. At a fundamental level this should be
Oil 5.3bn boe
expected given the maturity of the basin. According to DTI estimates, there are still significant resources to be found in
Undiscovered 8.6bn boe
the U.K. – between 3.5bn boe and 22bn boe. However, these estimates are subject to revision and are speculative – we have used the central case of 8.6bn boe in the chart above. While these potential volumes are meaningful, they must be
Gas 3.3bn boe
Produced 32.8bn boe
viewed in the context of a basin that has produced 33bn boe to date.
Sources: DTI and Simmons & Company International.
Activity Drivers – Norway Norwegian activity levels are far less volatile than those of
Norwegian drilling activity has been steadily increasing over
the U.K. due to greater participation of government in the oil
the last decade. Average annual rig demand has grown from
and gas sector. The Norwegian Government retains stakes in
the low-teens to peak at 23 rigs in 2001 before slipping back
major operators Statoil (82%) and Norsk Hydro (44%) and is
to 19 in the last two years. Monthly demand reached a peak
also the largest direct owner of Norwegian oil and gas
of 25 rigs in late 2000 and early 2001. This increase in
resources (approximately 30% of reserves and production)
activity has been driven by Statoil and Norsk Hydro, the two
through Petoro (a wholly owned state company managing the
largest operators in Norway whom account for almost 55% of
SDFI - State’s Direct Financial Interest).
the wells drilled offshore.
Norwegian Rig Count Vs. Brent Oil Price 30
Norwegian Wells Drilled (1982-2003) 35
200
Rig Demand 30
Rig demand trend line.
20
25
15
20
10
15
5
10
0
5
160 Brent Oil Price ($ / bbl)
Norwegian Rig Demand
180
Oil Price (RH Scale)
25
Exploration Appraisal
140
Development 120 100 80 60 40 20
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Sources: BHI Rig Count and Simmons & Company International.
0 1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Sources: Norwegian Petroleum Directorate (NPD).
SIMMONS & COMPANY INTERNATIONAL
9
Activity Drivers – Norway (continued)
The two Norwegian majors drilled 50% more wells in
Average discovery sizes in Norway have fallen from 100mm
2000-2001 than in the preceding two years (an additional 120
boe per discovery well before 1993 to under 50mm boe over
wells) and have subsequently reduced activity. The timing of
the last three years. Given the dominance of major oil
this peak activity level in winter months is quite unusual but
companies in Norway, it is not surprising that these
coincides with Statoil’s initial public offering in June 2001.
companies are now focusing their exploration efforts
Norsk Hydro’s activity was driven by both exploration and
elsewhere. Future resource potential in Norway is fairly
development drilling, including significant activity on the
evenly split between the North Sea, Norwegian Sea and
large Troll and Oseberg fields.
Barents Sea although the Barents and Norwegian Sea are much less mature and are likely to be more attractive to oil
Aside from the large domestic oil companies who dominate
companies. The North Sea sector is prolific but relatively
Norway, it is the international integrated oil companies that
mature with fields in this area having produced around 92%
make up the balance of activity. It should therefore be
of total Norwegian oil and gas production to date.
remembered that Norway is a highly concentrated market with few smaller players (note Saga Petroleum was acquired
Norwegian Oil & Gas Resource Maturity By Region
by Norsk Hydro and Statoil in 1999).
35
Operator
Type Of Well By Operator E&A Development Total
Statoil Norsk Hydro ConocoPhillips BP ExxonMobil Saga Total Shell Other Total
26% 19% 9% 9% 10% 10% 7% 6% 4% 100%
33% 25% 18% 8% 8% 4% 4% 1% 0% 100%
31% 23% 15% 9% 8% 6% 5% 3% 1% 100%
1,184
2,355
3,539
# Wells
Oil & Gas Resource (Billion boe)
30
Norwegian Offshore Wells By Operator (1966-2003)
Barents Sea Norwegian Sea North Sea
25
20
15
10
5
0 Produced
Discovered
Undiscovered
Sources: NPD and Simmons & Company International.
Norwegian North Sea
Sources: NPD and Simmons & Company International.
The Norwegian North Sea is relatively mature (and closer to The lack of smaller players in Norway has been a cause of
the U.K. analogy) having been the primary source of
concern for Norwegian authorities as exploration and
Norway’s exploration, development and production over the
appraisal activity declined from approximately 50 wells per
last 30 years.
year in the 1990’s to roughly 20 to 25 wells per year in 2002 and 2003. This situation is now being addressed with a few
Norwegian North Sea Total Oil & Gas Resource Base
smaller companies taking interests in Norway and being actively encouraged by the Government. (Norway is in the
Discovered 21.7bn boe
Oil 4.4bn boe
fortunate position of being less mature than the U.K. and can therefore follow U.K. initiatives to stimulate activity where appropriate – such as attracting smaller E&P companies to
Undiscovered 7.5bn boe
maximize recovery of smaller reservoirs or fields reaching the tail-end of production). Examples of this include Talisman’s recent acquisition of the Gyda field from BP, and the emergence of a fledgling E&P sector for example, Pertra.
Produced 20.0bn boe
Gas 3.1bn boe
Sources: NPD and Simmons & Company International.
10
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – Norway (continued)
Of the total recoverable resource base, estimated at 50bn boe,
Unfortunately the Norwegian Government has decided these
around 40% has been produced to date while only 15%, or
areas are too environmentally sensitive to be open to oil and
7.5bn boe, remains to be discovered. Future discoveries are
gas activity. Two petroleum licenses in Nordland VI had
likely to be much smaller in size than the Statfjord, Gullfaks,
been awarded in 1996 but activity has been suspended (one
Oseberg and Ekofisk fields that have been the backbone of
well drilled with no discovery). The most recent 18th
production in this area. Average resource size per discovery
licensing round offered 95 blocks for oil and gas activity but
well has declined from 82mm boe in the early 1990’s to
Nordland VI remains closed for the time being. Therefore
around 10mm boe in the last three years. Activity in this
activity will focus on improved recovery from existing fields
region will therefore be about managing the decline and
and the development of Ormen Lange. Exploration activity
encouraging near-field exploration and development. A
has averaged around 6 ‘wildcat’ wells per year and any future
significant increase in drilling activity over the medium-term
increase will depend on access to acreage.
is therefore unlikely in this region of the Norwegian shelf. Barents Sea Norwegian Sea The Barents Sea remains an untapped resource for Norway. Production from the Norwegian Sea began in 1993 and
Exploration activity has been sporadic. A total of 39
makes up the remaining 8% (~2bn boe) of Norwegian
production licenses have been granted and since the first well
production to date. Key fields in this area include Heidrun,
spudded in 1980, a total of 61 exploration wells have been
Draugen, Norne and Njord with future developments
drilled, including eight in 2001 and 2002. Interest amongst
dominated by the Ormen Lange gas field (2.5bn boe).
oil companies had been muted but the recent approval of the Snohvit LNG development (1.3bn boe), developments in the
Norwegian Sea Total Oil & Gas Resource Base
Russian sector of the Barents Sea (Prirazlomnoye oil field development) and a number of medium sized finds has reignited interest.
Undiscovered 7.2bn boe Discovered 9.5bn boe
Barents Sea Total Oil & Gas Resource Base
Gas 4.7bn boe
Oil 2.5bn boe
Produced 1.8bn boe
Gas 3.4bn boe Discovered 1.4bn boe
Undiscovered 5.9bn boe
Sources: NPD and Simmons & Company International. Oil 2.5bn boe
The area is less prolific than the North Sea with an estimated resource base of 18.5bn boe. Costs are also generally higher in the Norwegian Sea due to high pressure high temperature
Sources: NPD and Simmons & Company International.
(HPHT) reservoirs, deeper waters, remoteness from markets and sensitivity to environmental concerns. However, this
Total resources are estimated at 7.4bn boe with no production
area is much less mature then the North Sea with only 10%
to date and around 81% still estimated as undiscovered. The
of reserves already produced and 39% as yet undiscovered.
recent 18th licensing round included permissions to resume
Of the projected 7.2bn boe of undiscovered resources, the
operations on a number of blocks in this area which had been
majority is gas with the area designated Nordland VI and
suspended pending an environmental impact assessment. It
Nordland VII (off Lofoten Islands) deemed highly
now seems likely that three wells will be drilled on the
prospective.
acreage between autumn 2004 and spring 2005.
SIMMONS & COMPANY INTERNATIONAL
11
Activity Drivers – Norway (continued)
Looking ahead, Norway clearly has significant remaining resource potential. In addition, the Government is concerned
Norwegian Future Field Development Projects 2,500
about current exploration activity levels and is taking steps to Norway a more attractive investment opportunity for smaller E&P companies, opening up more acreage and showing flexibility in the fiscal regime. Ho wever, as Statoil and Norsk Hydro endeavor to become more international oil and gas companies, competition for funds may mean that Norway may no longer be able to rely on these companies to drive activity to the same degree as in the past.
2007
2,000 Gas Oil
1,500
2006
1,000
500
2004 2005
No Set Development Plan / Schedule
0 Or m en La ng e Sn Kv ohv ite it bjo rn Kr ist in Ty S rih k an arv sS o La r vr an s Gj oa Id SV un Ka olv m e ele on Go lia t De lta Va Gek rg ko So uth St ae Da r gn 25 y /5 -5 25 Trym /11 -1 6 Ka pp a Ga m Fr m ej Al a Ve a ph s a t Co ok
encourage this going forward. These steps include making
Sources: NPD and Simmons & Company International.
From a resource base perspective, the Barents Sea and acreage around the Lofoten Islands are highly prospective.
The Snohvit field will initially be produced via six wells plus
The Norwegian Petroleum Directorate estimates that
a CO2 injector to be drilled in 2004-05. A further two wells
undiscovered resources in this area could reach 7.6bn boe or
will be drilled in 2011. In addition, the Albatross reservoir
37% of the Norwegian total. It is therefore disappointing that
will be tied in using four wells, three of which will be drilled
the area around Lofotens remains closed to oil and gas
in 2005-06 with the final well scheduled for 2014. The
activities. However, the recent opening of the Barents Sea
Askeladd reservoir will not be tied in until 2014-15 when
southern area is welcome and will likely result in at least
eight wells are planned. Further, the Government has
three wells being drilled between autumn 2004 and spring
allowed exploration activity around Snohvit to continue and
2005. Success with these wells and development of Snohvit
we would expect further drilling to be done in order to
and (potentially) Goliath discoveries could help spark further
improve the economics of the Snohvit field. Ormen Lange
drilling in the area. In addition, resolution of the disputed
will be developed via 20 to 24 wells with drilling
Barents Sea boundary between Norway and Russia may help
commencing in early 2004.
open up further acreage. Similarly, activity on the Russian side of the boundary could offer further insights into the
18 th Licensing Round
plays geology and prospectivity. The Norwegian Government recently announced that 95 Future Developments
blocks (or part blocks) would be available for applications in the 18th biannual licensing round. This is a significant
Norwegian projects with development approval (or where
increase (200-300%) on acreage available in the prior three
approval is expected within the next four years) will access
rounds. This reflects the Government’s concern at current
around 5.9bn boe of reserves (22% oil / 78% gas). These 24
activity levels and a desire to increase activities in the near
developments are dominated by the massive Ormen Lange
future. Licenses have an initial term of six years.
and Snohvit gas projects, due on stream in 2007 and 2006
Applications will be submitted by March 15, 2004 and
respectively, which account for 3.4bn boe of reserves (57%
awards made in Q2’04.
of new development total). Excluding these projects the median reserve size is 56mm boe with only seven developments of the remaining 22 containing estimated reserves above 100mm boe.
12
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – Netherlands The Netherlands is an important component of the North Sea
As discussed, oil production is a relatively small part of
drilling market. In 2003, rig demand reached eight rig years
Dutch hydrocarbon production although the recent Hanze
with peak activity of 10 units in late September. The
field development, operated by Petro-Canada, produced
Netherlands is a jack-up market and has been very important
26mboed in 2002.
for drilling contractors with a strong jack-up presence (i.e. Noble, Ensco and Global Santa Fe).
2002 Dutch Offshore Gas Production (100% = 2.6bcfd)
Background
Other 10%
GDF 12%
The Netherlands produced approximately 1.2mmboed in
NAM 41%
2002. Production is dominated by gas (96%) with oil production a relatively minor 50mboed. Gas production is split 60:40 between onshore fields (4.3bcfd / 710mb oed) and
Wintershall 13%
the continental shelf (2.6bcfd / 430mboed). Dutch production is dominated by the onshore Groningen field, discovered in 1959, which produced 3bcfd (500mboed) or 42% of total production in 2002 but has been on the decline
Total 24%
Sources: SODM, Simmons & Company International.
in recent years. Future Developments Netherlands Oil & Gas Production (1996-2003)
Wintershall and GdF will play a disproportionately important
1,600
Oil
Daily Production (mboed)
1,400
role in future Netherlands activity. Both companies are
Gas
1,200
seeking to grow production with the Netherlands playing an
1,000
important part in their portfolios. This is borne out by recent
800
tender activity with Wintershall seeking information on three to four jack-ups for 1 well plus option programs commencing
600
early 2004. With additional programs likely from GdF,
400
NAM and Total, 2004 should see a similar activity levels to
200 0 1996
2003. 1997
1998
1999
2000
2001
2002
Sources: BP Statistical Review, SODM, Simmons & Company Intl.
NAM, a joint venture company between Shell and ExxonMobil, is the dominant producer in the Netherlands. The company produces around 800mboed of gas (67% of total production) primarily through the Groningen field and other smaller onshore fields. Offshore, NAM is less dominant, producing around 175mboed, or 40% of offshore production. Other important offshore operators include Total (operate 104mboed) and Wintershall (60mboed) which has significantly increased its position through the 2002 acquisition of Clyde Netherlands. Gaz de France (GdF) is also an important player operating ~50mboed offshore Netherlands.
SIMMONS & COMPANY INTERNATIONAL
13
Activity Drivers – Denmark Denmark is often overlooked in the North Sea picture but is
Danish Reserve Estimates
an important part of the North Sea rig market. In 2003 an average of eight jack-ups (0 floaters) were fully utilized in
Producing 1.8bn boe Planned 0.1bn boe
Denmark (27% of North Sea jack-up demand). Activity in
Oil 0.5bn boe
Denmark has been on the increase in recent years with nine exploration and appraisal wells and 27 development wells
Possible 0.7bn boe
drilled in 2002 with a similar level anticipated in 2003 and 2004. Produced 1.9bn boe
Background Danish production of oil and gas totaled 503mboed in 2002, a
Gas 0.2bn boe
Sources: DEA, Simmons & Company International.
new record. Production volumes increased rapidly in the 1980’s with the development of the Dan, Gorm, Skjold and
Operations in Denmark are dominated by the DUC (Danish
Tyra fields which account for 77% of oil and 65% of gas
Underground Consortium) formed in 1962 to explore for oil
produced in Denmark to date. These four fields, particularly
and gas in Denmark. Maersk Oil & Gas, a subsidiary of AP
Dan, Gorm and Tyra remain the backbone of Danish
Moller, operates on behalf of DUC partners (Maersk 39%,
production representing 54% of oil and 37% of gas
Shell 46%, ChevronTexaco 15%). Maersk Oil & Gas
production in 2002.
operates 16 fields in Denmark with DONG (state-owned E&P company) and Amerada Hess making up the remainder.
Danish Oil & Gas Production (mboed) E&A Wells By Operator (1966-2003)
600
Danish Exploration & Appraisal Wells By Operator Since 1966 Since 2000 % Since 2000 Maersk Oil & Gas 78 31 57% DONG 11 11 20% Amerada Hess 8 3 6% Statoil 12 2 4% ConocoPhillips 4 2 4% ChevronTexaco 81 0 0% Other 25 5 9% Total 219 54 100% Sources: DEA, Simmons & Company International.
Oil & Gas Production (mboed)
500
400
Gas Oil
300
200
100
20 02
20 00
19 98
19 96
19 94
19 92
19 90
19 88
19 86
19 84
19 82
19 80
19 78
19 76
19 74
19 72
0
Sources: DEA, Simmons & Company International.
Unsurprisingly, it is these companies that dominate drilling in Denmark, accounting for 83% of E&A wells drilled over the
In total there are 20 producing fields in Denmark with
last four years. It is interesting to note the more pro -active
reserves heavily concentrated in the largest six fields (1.4bn
participation of DONG, the state-owned company in
boe versus 400mm boe in remaining 14). Total remaining
operations. Previously, DONG held 20% interests in
reserves in Denmark are estimated at 2.6bn boe (69% oil)
production licenses as part of the Danish fiscal regime
which includes 1.8bn boe from currently producing or
(managing the state’s participation in hydrocarbon licenses).
approved fields and 800mm boe from currently planned or
Now DONG is operator of three producing fields and several
possible developments.
exploration licenses and has an objective of further developing small fields in Denmark.
14
SIMMONS & COMPANY INTERNATIONAL
Activity Drivers – Denmark (continued)
Future Developments
In addition to new fields being brought on stream further development work is also likely on existing fields and
Fields scheduled to be brought on stream over the next five
particularly Dan and Halfdan. The Danish authorities expect
years are generally smaller in nature than those developed in
production to grow in 2004, driven by recent field
recent years (two largest recent developments (Halfdan
development activity, before declining in 2005. Drilling
(540mm boe) and South Arne (260mm boe) fields brought on
activity is expected to remain constant in 2004 before
stream in 1999).
declining in 2005 without further exploration success.
Danish Future Field Developments Future Field Developments Fields Adda Boje Area Alma Elly Amalie Freja Total
Start Up 2005 2005 2007 2007 -
Oil (mmboe) 6 6 6 6 13 6 44
Reserves Gas (bcf) 0 0 38 189 113 0 340
Total (mmboe) 6 6 13 38 32 6 101
Sources: DEA, Simmons & Company International.
North Sea Drilling Contractors North Sea Jack-Up Fleet By Contractor – Dec 17 2003
Most major drilling contractors have a presence in the North
SME NO RDC 3% 3%
Sea market in addition to a number of smaller “domestic”
NE 25%
players. In addition, some contractors choose to deploy only GSF 22%
jack-up or floater rigs in this market. Jack-Ups The North Sea jack-up market has four major players (seven to eight rigs per contractor) and two companies with one rig a
Maersk 25%
ESV 22%
piece. Noble Corp and Maersk have the largest jack-up fleets in the North Sea (eight units each) closely followed by Ensco
Sources: Platts, OneOffshore, Simmons & Company International.
and Global Santa Fe (seven units each). Maersk and Ensco enjoy particularly strong positions in Denmark. In the first
North Sea Jack-Ups By Status/Contractor – Dec 17 2003 9
Maersk E&P subsidiary while Ensco has been successful in
8
winning work with DONG. Historically, Noble has had a
7
strong position in the Netherlands and this continues to be an
6
important market for it alongside the U.K. Global Santa Fe has a number of units working in the Netherlands but the U.K. remains its primary market for jack-ups. The Smedvig and Rowan jack-ups remain on long-term charters in Norway and the U.K. respectively.
North Sea Fleet
instance, Maersk is the obvious drilling contractor for the
Available Working
5 4 3 2 1 0 NE
Maersk
ESV
GSF
SME NO
RDC
Sources: Platts, OneOffshore, Simmons & Company International.
SIMMONS & COMPANY INTERNATIONAL
15
North Sea Drilling Contractors (continued)
Floaters
North Sea Floaters By Status/Contractor – Dec 17 2003 18 16
in the North Sea (42% of the total), only eight of which are
14
currently working. Transocean is focused on the northern
12
sector of the U.K. and Norwegian markets which have suffered most from reduced activity in recent years. A
North Sea Fleet
The floater market is dominated by Transocean with 17 units
Available Working
10 8
number of contractors have two to four semis in this market
6
including Global Santa Fe, Diamond and more regional
4
players such as Fred Olsen (Norway), Odfje ll (Norway),
2
Smedvig (Norway) and Stena.
0 RIG
GSF
DO
FOE NO
Odfjell
Stena
SME NO
NE
SPM IM Petrolia
Sources: Platts, OneOffshore, Simmons & Company International.
North Sea Floater Fleet By Contractor – Dec 17 2003
SME NO 5%
N E SPM IM 3% 3%
Petrolia 3%
Stena 8% RIG 42%
Odfjell 8%
FOE NO 10%
DO 9%
GSF 9%
Sources: Platts, OneOffshore, Simmons & Company International.
Conclusions North Sea rig demand will likely remain essentially flat in
due to the overhang of cold-stacked units in this market. We
2004 at ~ 57 rig years of demand. However, utilization
would expect to see day rates improve from current cash cost
should improve, by approximately 15% to 90% overall, due
levels.
to the reduction in available fleet from 76 units in early 2003 to 64 units in 2004 (excluding 10 cold stacked units).
In the medium term there are a number of activity drivers that could drive an improvement in North Sea rig demand. These
The jack-up market will remain healthy in 2004 with
include greater participation of independent oil companies,
practically full utilization expected, an improvement of ~10%
the 18th and 21st licensing rounds in Norway and the U.K.,
over 2003 due to reduced supply and potential for increased
incentives from Government, the opening of acreage in
demand. The potential for day rate appreciation exists,
Norway, the continued success of companies aggressively
particularly during peak activity in Q3-Q4.
pursuing opportunities in the North Sea (e.g. Apache, EnCana) and continued strong commodity prices.
On current expectations, the North Sea floater market will experience a significant increase in utilization during 2004, to
In the longer term, the North Sea is maturing and will require
79% from 64% in 2003. This is driven by a reduction in the
constant improvements in cost and productivity to compete
available fleet from 42 units to 32. However, the potential
for capital.
for significant day rate appreciation is limited in our view
16
SIMMONS & COMPANY INTERNATIONAL
Analyst Certification and Disclaimer Analyst Certification: I, Ruairidh Stewart, prepared this report and hereby certify that the views expressed in it to the best of my knowledge accurately reflect my personal views about the subject compan(ies) and its (their) securities; and that, I have not been, am not, and will not be receiving direct or indirect compensation in exchange for expressing the specific recommendation(s) or views in this research report. Disclosure: This report is based on information obtained from sources which Simmons & Company International believes to be reliable, but Simmons & Company International has not verified the information and does not represent or warrant its accuracy or completeness. The opinions, ratings and estimates contained in the report represent the views of Simmons & Company International as of the date of the report, and may be subject to change without prior notice. For detailed rating information, go to http://publicdisclosure.simmonsco-intl.com. Research analysts compensation is based upon (among other things) the firm's general investment banking revenues. Simmons & Company International may seek compensation for investment banking services from NE, ESV, GSF, SME.OL, RDC, RIG, DO, SPMI.MI and other companies for which research coverage is provided. The firm would expect to receive compensation for any such services. One of the analysts, or a member of the analyst's household, responsible for the preparation/supervision of this report has a Long Stock position in GSF. Simmons & Company International has received compensation from ESV for investment banking services in the past 12 months. Simmons & Company International has received compensation from GSF for investment banking services in the past 12 months. Simmons & Company International has received compensation from SME.OL for investment banking services in the past 12 months. Simmons & Company International will not be responsible for the consequence of reliance upon any opinion or statement contained in this research report. This report is confidential and may not be reproduced in whole or in part without the prior written permission of Simmons & Company International. Please note: All electronic mail sent to or received from this address will be archived by Simmons & Company International's electronic mail system and is subject to review by someone other than the recipient. Nothing in the research report is, or should be relied upon as, a promise or a forecast and no representation or warranty is given as to the accuracy, achievement or reasonableness of any future projection, estimate, forecast or statement about future prospects. The value of securities can go down as well as up and past performance is not a guide to future performance. The research report is directed only at and may only be communicated to persons outside the EEA; persons who have professional experience in matters relating to investments who fall within the definition of investment professionals in Article 19(5) Financial Services and Markets Act (Financial Promotion) Order 2001 (as amended) (“FPO”); persons who fall within Article 49(2)(a) to (d) FPO (high net worth companies, unincorporated associations etc.) or persons who are otherwise market counterparties or intermediate customers in accordance with the FSA Handbook of Rules and Guidance (“relevant persons”). The research report must not be acted on or relied upon by any persons who receive it within the EEA who are not relevant persons. Simmons & Company International does not treat the recipient of the research report as its customer and it is not, therefore, responsible for providing such recipient with legal or regulatory protections. The research report is provided solely for information purposes. It does not constitute an offer or recommendation to sell or an invitation to offer to buy an interest in the subject of the research report. The research report is not intended to be an inducement to enter into a contract nor is it intended to form the basis of an investment decision, and it should not be treated as if it were or relied upon in any way. Receipt of the research report does not constitute the giving of investment advice by Simmons & Company International. Simmons & Company International is registered with the SEC and is a member of NASD and SIPC. Simmons & Company International Limited is authorised and regulated by the Financial Services Authority to undertake designated investment business in the United Kingdom.
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