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Oil & Gas UK 2007 Economic Report
2007 Economic Report
Index
1. Foreword 4 2. Contribution to the Economy 6
3. Providing for the UK’s Energy Needs 14
4. Oil and Gas Markets 18
5. Outlook for the UKCS in 2007 24
6. Industry Perspectives 34
7. Appendix A. UKCS Fiscal Regime 47
B. Recent Initiatives to Promote the UKCS 49
C. Glossary of Terms and Abbreviations 51
“Oil & Gas UK is the trade association for the new era, a stronger voice for a vital UK industry”
Page �
Oil & Gas UK | 2007 Economic Report
1. ForewordWelcome to Oil & Gas UK’s first Economic Report on our offshore oil and gas industry. This report reveals more about one of the
country’s well kept secrets: an industry which in 2006 provided 70% of national energy needs, invested more than £5.5 billion,
spent another £5.5 billion on operations and contributed £9 billion in direct taxation to the Exchequer. Our industry today supports
employment of some 480,000 people across the whole UK, with 380,000 jobs related to domestic production and a further 100,000
to the exports of oilfield goods and services. Even after forty years, we are still the twelfth largest oil and gas producer in the world
with many years of productive life to come. Investors are continuing to pursue new opportunities and drilled 69 exploration and
appraisal wells and developed 13 new fields last year. The UK is increasingly emerging as a global provider of oilfield goods and
services; exports from the sector are currently growing at 10% per annum and are now worth £ 4 billion a year.
The search for new oil and gas is increasingly focusing on high risk, technically and commercially challenging developments such
as to the west of the Shetlands, in high pressure high temperature opportunities and with heavy oil. All pose considerable risks
and must compete internationally to attract the necessary investment. It should also be recognised that many of the older fields
still have a great deal of life left in them, as oil and gas companies continue to demonstrate successfully. Operational excellence
combined with the sustained application of new technologies, such as enhanced reservoir modelling and increasingly targeted
extended-reach drilling, will continue to enhance recovery of oil and gas from these fields and defer their decommissioning. Older
fields and infrastructure place increasing demands on an industry which is determined to achieve the highest standards of asset
integrity and safety; these benefit from an ever closer working relationship between field operators, contractors and the supply
chain.
However, despite the current success of this industry, the UK now has to compete more than ever to attract the investment and
resources needed to extract the estimated 25 billion barrels of oil and gas which are still to be recovered. The economics of the
now mature UK continental shelf (UKCS) poses as much of a challenge today as in the days of lower oil prices; the costs of exploring,
developing and producing have risen sharply during the past few years, in an oil and gas province which was already among the
most expensive in the world. The industry was pleased to see the determination expressed by the government in its recently
published Energy White Paper to exploit these resources to the full and to boost investment in the UKCS. However, an increasingly
uncompetitive fiscal and regulatory regime is one of the biggest threats to the future our industry. This is made all the more
apparent by low wholesale gas prices, now prevailing, which are incompatible with the current tax and regulatory regime.
We are entering a new and crucial phase in the industry’s lifecycle. The decisions taken today will determine the shape of our oil
and gas production for several decades to come and the whole industry needs to be involved in these decisions. The launch of Oil &
Gas UK is designed to meet this task with the creation of a brand new trade association for one of Britain’s most successful industrial
sectors. For the first time in its 40 year history, the offshore oil and gas sector has a pan-industry, representative forum which is
open to all companies active in the UKCS, from super majors to large contractors and from small independent oil companies to the
multitude of small and medium sized enterprises (SMEs) working in the supply chain. The new organisation is growing rapidly, with
more than 60 companies in membership. It will provide a coherent voice for industry to put forward its case to ensure a long and
healthy future and address the technical, financial, economic, safety, environmental and social challenges that lie ahead.
The Energy White Paper confirms that we will continue to remain reliant on oil and gas for the bulk of our energy needs for some
decades to come (74% now, 79% forecast in 2020), even as we move to a much greater use of renewable sources. Every last drop
not produced by ourselves will have to be imported at considerable cost to the economy, the Exchequer and security of supply. But,
if investment is sustained, the UKCS could still be providing about 25% of the country’s gas and 60% of its oil needs in 2020 and, in
addition, see the UK emerge as a global leader in oil and gas technology, goods and services. Our new organisation is committed to
working closely with the government to make this a reality.
Oil & Gas UK is ready for the challenge!
Malcolm WebbChief Executive
Oil & Gas UK
Contribution to the Economy
Page 7
Oil & Gas UK | 2007 Economic Report
2. Contribution to the Economy
Oil and Gas Production
The UK continues to produce very large volumes of oil and gas from its continental shelf (UKCS). During 2006, some 1.1 billion
barrels of oil equivalent1 (boe) were recovered, making a total of just over 36 billion boe over the last forty years. These volumes
satisfied the vast majority of domestic demand. In the case of oil, production contributed 588 million barrels (i.e. 96%) of the 615
million barrels consumed. For gas, 80 billion cubic metres (bcm) were produced, or 92% of the 87 bcm consumed; the remainder
was met by imports.
Figure 1: UK Oil and Gas Production 1970-2006
In world terms, the UK remains the 4th largest gas producer and is now ranked 15th largest oil producer. For combined oil and gas
production, the UK is ranked 12th, making it more significant than Nigeria, Kuwait or Indonesia.
Figure 2: Major Oil and Gas Producing Countries 2005
The significance of indigenous oil and gas is most obvious in the context of the UK’s total energy picture. In 2006, 70% of all energy
consumed was accounted for by oil or gas produced from the UKCS, with the contributions of nuclear power, domestic coal and
renewable sources each being in single percentage figures.
The fact that demand for oil and gas is forecast to increase in future highlights the importance of sustaining domestic production,
with any that is not so produced having to be imported. In addition, if recovery of reserves from the UKCS is not maximised, the
notable benefits to the economy, through high value adding employment, the continued support and growth of the supply chain
and the payment of taxes, would be reduced.
� “Barrelofoilequivalent”(boe)equatesgasvolumeswithoil,sothatasinglemeasurecanbemadeofthetwoincombination.
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
1970 1975 1980 1985 1990 1995 2000 2005
Mill
ion
boep
d
GasOil
Source: DTI
0.0 5.0 10.0 15.0 20.0
Indonesia
Kuwait
Nigeria
United Kingdom
Algeria
Venezuela
United Arab Emirates
Norway
Mexico
China
Iran
Canada
Saudi Arabia
USA
Russian Federa�on
Million boed
GasOil
Source: BP Sta�s�cal Review
Page 8
Oil & Gas UK | 2007 Economic Report
Capital Investment, Expenditure & Gross Value Added
Production and manufacturing industries together invested £16 billion in 2005 in the UK, no less than one third of which (over
£5 billion) was made by oil and gas explorers and producers and the supply chain on their behalf, as shown in Figure 3. No
other industrial sector came anywhere near this rate of investment which is indicative of the industry’s importance for productive
investment and its commitment to recovering the maximum amount of oil and gas within the prevailing business climate.
Figure 3: Industry Investment 2005 by Sector
However, investment forms only one part of the industry’s annual expenditure. Figure 4 shows that oil and gas producers have
spent a total of £370 billion (2006 prices) exploring for, developing and producing reserves from the UKCS since 1970.
Figure 4: UK North Sea Expenditure 1970-2006
The ‘value added’ by an industry sector is the value of its sales after deduction of its costs. Oil and gas production contributed
£22 billion to the UK economy’s ‘value added’ (13% of all production and manufacturing industries) in 2006. Given that supply chain
sales are dominated by high technology goods and services, there is a further sizeable contribution to the UK’s ‘value added’ not
represented in Figure 5.
Figure 5: UK Oil and Gas Industry Gross Value Added 2005
2% Mining & Quarrying
34% Oil & Gas
14% Food, Beverages & Tobacco
10% Pulp & Paper
10% Chemicals & Products
8% Basic Metals
3% Machinery & Equipment
3% Electrical & Op�cal
3% Transport
13% Other Manufacturing
Source: Na�onal Sta�s�cs
0
2
4
6
8
10
12
14
16
1970 1974 1978 1982 1986 1990 1994 1998 2002 2006
£ bi
llion
200
6 pr
ices
Explora�on Costs (£52 billion)Development Costs (£189 billion)Opera�ng Costs (£126 billion)
Source: DTI
1% Mining & Quarrying
13% Oil & Gas
13% Food, Beverages & Tobacco
12% Pulp & Paper
10% Chemicals & Products
9% Basic Metals
7% Machinery & Equipment
9% Electrical & Op�cal
7% Transport
18% Other Manufacturing
Source: Na�onal Sta�s�cs
Page 9
Oil & Gas UK | 2007 Economic Report
Tax Revenues
The economy has benefited from over £230 billion (2006 prices) in UKCS taxes since 1968 (see Appendix A for an explanation of the
tax regime). In addition, taxes are collected on activities induced by the industry’s expenditure on investment and operations. Figure
6 shows how tax receipts almost doubled from £5.4 billion in 2004-05 to £9.8 billion in 2005-06 as a result of high commodity prices,
as well as the accelerated payment of Corporation Tax announced in March 2005. However, several factors caused tax revenues to
be lower than forecast at £9.1 billion in 2006-07. Despite oil prices remaining high and the increase in the Supplementary Charge to
Corporation Tax announced in December 2005, much higher costs, falling gas prices and declining production reduced the industry’s
margins and, therefore, taxable income. It is projected that continued cost pressures, lower gas prices and declining production will
result in a further reduction in tax receipts in 2008-09.
Figure 6: UKCS Taxes 1991-2008
Balance of Trade
Oil and gas production, even in its current mature state, continues to have a large, positive effect on the UK’s balance of trade. In
2006, the balance in all goods and services was in deficit by £54 billion. If all indigenously produced oil and gas had been imported,
the balance of trade would have suffered by a further £30 billion, resulting in a total deficit of £84 billion.
The net balance of trade in oil and gas (including crude, oil products and natural gas) has been in decline since 2001 and became
negative to the tune of £400 million in 2005. This deficit widened in 2006 to £3.9 billion, accounted for by oil more than gas.
However, increasing oil production, as is expected in 2007 and 2008, should improve matters in the short term, although declining
gas production will work against this. Oil, though, remains the more valuable of the two commodities.
Figure 7: UK Balance of Trade: Crude Oil, Oil Products and Natural Gas 1995-2006
In addition to production, the UK’s balance of trade benefits from the export of goods and services to other oil and gas regions
around the world. Operators overseas are increasingly recognising the expertise which the supply chain in Britain possesses, after
some forty years of development and operation of domestic production. They are seeking to use this technology and know-how,
especially subsea expertise.
-2
0
2
4
6
8
10
12
1991
-92
1992
-93
1993
-94
1994
-95
1995
-96
1996
-97
1997
-98
1998
-99
1999
-200
0
2000
-01
2001
-02
2002
-03
2003
-04
2004
-05
2005
-06
2006
-07
2007
-08
£ bi
llion
2006
pric
es
Projection Total TaxSupplementary Corporation TaxCorporation TaxPetroleum Revenue TaxRoyalty
Source: HM Treasury
Projected
-100
-80
-60
-40
-20
0
20
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Bala
nce
of T
rade
£ b
illio
n
Oil, oil products & gas
All goods & services
All goods & services if no indigenous oil & gas produc�on
Source: Na�onal Sta�s�cs
Page 10
Oil & Gas UK | 2007 Economic Report
Since 1999, exports from oil and gas supply chain companies based in Scotland alone have increased by 10% per annum, whereas
overall exports of manufactured goods have fallen by 5% per annum. On average, 27% of the oil and gas supply chain’s sales in
2005 were to overseas markets, amounting to £4 billion worth of activity; particular sub-sectors like subsea export as much as 50%
of their products and services and have experienced exports’ growth of 20% per annum in recent years. Expenditure in the global
oil and gas supply chain is expected to increase by 60% from £450 billion in 2001-05 to £700 billion in 2006-10, so there are major
opportunities for further growth of export sales by supply and service companies.
Contribution to Employment
In 2006, the total employment provided by the oil and gas sector in the UK was estimated to have risen to 480,000, of which
380,000 were involved in domestic production; they comprised 30,000 people in oil and gas companies and major contractors,
260,000 within the wider supply chain and 90,000 supported by economic activity induced by oil and gas employees’ spending
throughout the economy. Up to an additional 100,000 people are employed in export activities by supply chain companies. The
number of jobs involved in domestic production is not expected to increase further in 2007, given the lower investment forecast,
but there could be increased demand for people in export markets.
Figure 8: UK Oil and Gas Industry Employment 1991-2007 (excluding export activity)
A recent Oil & Gas UK study has revealed a more optimistic picture for industry demographics than was commonly perceived. The
average age for the total workforce offshore was found to be 41 years which is the expected average for a workforce generally
ranging from 20 to 60 years old.
Figure 9: UK Oil and Gas Industry Offshore Employment by Age 2006
Individual age profiles for occupational categories demonstrate that the workforce is distributed fairly evenly in some occupations
like production and electrical roles, but weighted in others. Offshore installation managers and rigging personnel show a much
higher age distribution than, for example, those providing well services.
The numbers of females employed by the industry has increased gradually during recent years. In 2006, slightly fewer than 1,800
were working offshore, the majority employed in the catering sector. The age profile for female workers was weighted towards the
younger age brackets, with an average of 34.1 years.
-
100
200
300
400
500
600
91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07
Thou
sand
s of
jobs
Induced
Oil and gas companies
Supply chain
Source: Experian / ONS / DTI
forecast
0
2
4
6
8
10
12
14
16
Under18
18 - 23 24 - 29 30 - 34 35 - 39 40 - 44 45 - 49 50 - 54 55 - 59 60 - 64 65+
Age in Years
% o
f Em
ploy
ees
Source: Vantage POB
Page 11
Oil & Gas UK | 2007 Economic Report
All occupations demonstrate a need for continued recruitment efforts amongst the under-24s to avoid a potential shortage in due
course. This is particularly important in those occupations with higher average ages. Recruitment efforts are also required in the
30-34 age bracket, to avoid a potential shortage of supervisory personnel in future, although the recruitment of skilled personnel
from other sectors is one potential solution for this. However, oversubscribed training and graduate schemes run by operators and
industry bodies such as OPITO suggest that the issue may not, contrary to various reports, be the attractiveness of the industry.
Looking at the broader picture, there are distinct regional clusters of oil and gas employment within the UK. Over 100,000 highly
skilled oil and gas jobs are provided in Scotland alone because of the presence of the industry. When total economic activity is
included, the industry provides employment for around 150,000 people in Scotland. Four parliamentary constituencies in the
Aberdeenshire area account for no less than 38% of all UK jobs supported by offshore oil and gas. Outside Aberdeenshire, other
regions enjoying substantial employment associated with the industry are Eastern England (5%), North West England (6%) and
South East England, including London (21%).
Note: These percentages refer to the proportion of the total jobs supported by the industry which are in these areas.
Figure 10: UK Oil and Gas Industry Employment by Region 2004
Examining the distribution of supply chain jobs indicates that the range is diverse. However, a few key sectors are especially
noteworthy: metal products, construction and engineering account for 16%, 15% and 8% of total jobs respectively. There are
also substantial purchases from banking, finance and insurance (5%), the legal sector (8%) and “other business and professional
services” (12%).
Figure 11: UK Oil and Gas Industry Employment by Sector 2004
Source: Experian Business Strategies
Scotland
London
South East
North West
Eastern
Yorkshire and Humber
North East
West Midlands
South West
East Midlands
Wales
Northern Ireland
Construc�on
Structural Metal Products & Goods
Other Business & Professional Services
Engineering Ac�vi�es
Legal Ac�vi�es
Primary Produc�on Industries
Machinery & Equipment
Transport & Communica�ons
Educa�on, Public Admin & Denfence
Banking, Finance & Insurance
Real Estate & Rental
Hotels & Catering
Other Services
Other
Source: Experian Business Strategies
Page 12
Oil & Gas UK | 2007 Economic Report
The numbers on the map below, Figure 12, refer to Westminster’s parliamentary constituencies. A full list of these constituencies
may be found on Oil & Gas UK’s website at http://www.oilandgasuk.co.uk/issues/economic/index.htm.
Figure 12: UK Oil and Gas Industry Employment by Parliamentary Constituency
Providing for theUK’s Energy Needs
Page 1�
Oil & Gas UK | 2007 Economic Report
3. Providing for the UK’s Energy Needs
Primary Energy Demand
Oil and gas together met three quarters of primary energy demand in 2006 and demand is forecast to increase significantly. Under
DTI’s ‘favourable to coal’ scenario described in the 2006 Energy Review, oil and gas together will contribute 78% of primary energy
demand by 2020, while under the ‘favourable to gas’ scenario their contribution will rise to 83%. Both scenarios are based on the
same assumptions regarding the future provision of nuclear and coal plant and their availability. The difference between the two
scenarios is the extent of fuel-switching between gas and coal from 2006 onwards as a result of price differentials.
Figure 13: UK Primary Energy Demand 1970-2020
In contrast to oil and gas, the contribution of coal to meeting primary energy demand falls from 20% in 2006 to 10-14% in 2020,
depending on the scenario considered. Under current plans for nuclear plants, the contribution of nuclear to primary energy
demand falls from 7% in 2006 to only 3% in 2020. While the share of renewables doubles between 2005 and 2020, it grows from
such a small base that it will still only satisfy 4-5% of primary energy demand at the end of those 15 years.
Electricity Generation
Oil is of central importance in the transport sector, but in power generation its use is very small and diminishing. However, the use
of gas in electricity generation is projected to increase substantially, from some 36% currently to 60% in 2020 in the ‘favourable to
gas’ case and 54% in the ‘favourable to coal’ case.
Figure 14: UK Electricity Generation 2000-2020
Meanwhile, coal’s share of electricity generation is anticipated to fall in both of DTI’s scenarios, from 34% in 2005 to 21% (‘favourable
to coal’) and 15% (‘favourable to gas’) and the contribution of nuclear is assumed to be immune to relative coal and gas prices, so
its share falls from 21% to 7% in both scenarios, all within the same time frame.
0
20
40
60
80
100
70 75 80 85 90 95 00 05 10 15 20
%
ElectricityImports
Renewables
Nuclear
Coal
Gas
Oil
Note: Energy use only. The projec�ons above are an average of the 'favourable to gas' and 'favourable to coal scenarios.' Source: DTI
0
20
40
60
80
100
00 05 10 15 20
%
Imports
Pumped Storage
Renewables
Nuclear
Coal
Gas
Oil
Source: DTINote: The projec�ons above are an average of the 'favourable to gas' and 'favourable to coal sce
Page 16
Oil & Gas UK | 2007 Economic Report
Security of Energy Supply
Oil and gas from the UKCS have provided security of supply for much of the past three decades and are forecast to continue to
meet a significant proportion of oil and gas demand. The UK has been self-sufficient in oil for the 25 years to 2005, with indigenous
production satisfying 96% of demand in 2006. Assuming that new developments proceed as planned, it is expected that all oil
needs will again be met by domestic production during the years 2007 to 2009. Nonetheless, action needs to be taken urgently to
reverse the province’s declining competitiveness and hence its attractiveness for international investment, so that new reserves
can continue to be found and developed. If this investment materialises, the UK would be able to meet about 60% of forecast oil
demand in 2020 from indigenous production; if not, only about 25% of such demand will be satisfied from its own resources.
Figure 15: UK Oil Production vs Consumption 1970-2020
The UK became a net importer of gas in 2004 after a decade of self-sufficiency and in 2006 indigenous production satisfied 92% of
demand (it is worth noting that, contrary to many perceptions, Britain has not been self sufficient in gas since North Sea production
began in the late 1960s; significant quantities were imported from Norway between the late 1970s and the early 1990s). Given the
rising demand for gas forecast during the next 15 years and the mature status of the UKCS, domestic production is expected to make
a declining, but still important contribution. Current production plans would meet about 10% of the UK’s gas demand in 2020, but,
with the right conditions and sustained investment, this could be 20-25% of such demand.
Figure 16: UK Gas Production vs Consumption 1970-2020
This declining UKCS production should not be seen as a cause for concern regarding security of gas supplies, provided that sources
of new supply are diverse and markets are open. The success of the UK in attracting investment in new gas import infrastructure
is, by any measure, impressive (see Figure 23, New Import Projects). The diversity of these supplies is evident: major new pipelines
from Norway and The Netherlands, a trebling of the import capability of the continental Inter-Connector and new liquid natural
gas (LNG) terminals on the Thames estuary, at Tees-side and in south Wales, the combined capacity of all of which is similar to
today’s total demand. The LNG will be sourced from a variety of supply locations in the Middle East, north and west Africa and the
Caribbean. A world market in LNG is beginning to develop, albeit broadly split into two between the north Atlantic and the western
Pacific, linked however by the ability of cargoes from the Arabian Gulf to feed both markets. It is expected that there will be a four-
fold growth in LNG shipments worldwide between 2000 and 2020 (and five-fold by 2030). This evolution of an LNG market has
introduced a new and flexible dimension to international gas trading and adds to security of supply, especially in a market such as
Britain’s which is open, liquid and has responsive pricing mechanisms.
0.0
0.5
1.0
1.5
2.0
2.5
3.0
1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014 2018
Mill
ion
boep
d
Produc�on: poten�alProduc�on: current plansOil Consump�on
Forecast
Source: DTI / Oil & Gas UK
0
20
40
60
80
100
120
140
160
1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014 2018
Billi
on c
ubic
met
res
Produc�on: poten�alProduc�on: current plansGas consump�on Forecast
Source: DTI / Oil & Gas UK / Na�onal Grid
Oil and Gas Markets
Page 19
Oil & Gas UK | 2007 Economic Report
4. Oil and Gas MarketsOil and gas prices remain cyclical and both have recently fallen from the heights seen in 2005-6, although oil has risen again during
2007. Price movements have both contributed to and constrained activity in the oil and gas sector in 2006; while the rapid rise in
2004-5 encouraged investment, costs have now risen on the back of those higher prices, making many investments less attractive
now, to a lesser extent in oil but a greater extent in gas.
Oil Prices
Figure 17: Daily Brent Crude Price 2005-2007
Many commentators had predicted that the rate of increase in the oil price since 2002 was unsustainable. Indeed, during 2004,
the average price rose by a third, in 2005 by another 42%, but in 2006 by only a fifth to $65/bbl, peaking in that summer, as shown
in Figure 17. It then fell sharply, but has bounced back up again in the first five months of 2007, reaching $70/bbl at the time of
writing (end of May).
Figure 18: Annual Brent Crude Price 1965-2006
During the second half of 2006 and early 2007, the US dollar has weakened against sterling. For companies whose revenue is in
dollars but whose costs are mainly in sterling, a stronger pound means that the expense of developing and operating on the UKCS
absorbs a larger share of revenues than previously.
In the combined circumstances of volatile commodity prices, a stronger pound and increasing costs, the vulnerability of the
industry’s cash flow and its investors’ confidence to fiscal uncertainty is being exposed. In particular, the recent tax increases which
significantly reduce global competitiveness are undermining this confidence, itself founded previously on a clear understanding of
the UK’s fiscal and regulatory predictability. When prices are high, the temptation to garner more of the available economic rent
in the short term has to be matched by both a wariness of the effects of subsequently falling prices and an appreciation of the
potential damage which could be done in the longer term.
35
40
45
50
55
60
65
70
75
80
85
Jan 05 Mar 05 May 05 Jul 05 Sep 05 Nov 05 Jan 06 Mar 06 May 06 Jul 06 Sep 06 Nov 06 Jan 07 Mar 07
$ pe
r ba
rrel
mon
ey o
f the
day
Source: EIA
0
10
20
30
40
50
60
70
80
90
100
1965 1970 1975 1980 1985 1990 1995 2000 2005
Pric
e pe
r ba
rrel
200
6 pr
ices
$/bbl£/bbl
Source: EIA and Bank of England
Page 20
Oil & Gas UK | 2007 Economic Report
UK Gas Market and Prices
The gas market has undergone unprecedented changes in the past two years and, in particular, the past 12 months. During the
period 2004-6, wholesale gas prices in Great Britain rose significantly on the back of high oil prices and an expectation of supply-
demand tightness during winter, especially the one of 2005-6, combined with rigidities in the European market1. In the event, that
winter was especially difficult for industry with high, peak prices occurring both early on (late November – early December) and
towards the end (late February – early March); in addition, prices generally were at or above those on the continent of Europe,
where oil indexation is the normal means of pricing gas. High gas prices also affected electricity prices in Britain, because of
the extent to which electricity is produced from gas. For domestic and most commercial consumers, although gas prices rose
appreciably, there was not the same exposure to short term fluctuations, because these markets are mainly supplied through longer
term contractual arrangements which dampen price movements.
However, in the past 12 months, wholesale gas prices in Britain have fallen substantially, as new supplies have come on-stream
with the completion of two new pipelines, one from Norway and one The Netherlands. Through a very mild winter, 2006-7, these
pipelines have delivered much new gas to the market (see Figure 19), such that wholesale prices have fallen to less than half
of those indicated by oil indexation. This is good news for all UK consumers, but less good for producers, especially those with
interests in the gas-only provinces of the southern North and Irish Seas, and those trying to develop gas west of Shetland where
no pipelines exist to bring the gas to market. It also creates an awkward differentiation with the central and northern North Sea,
where oil predominates. However, overall costs are being driven mainly by the search for and development of higher priced oil, at
the expense of gas further south and west.
Figure 19: UK’s Sources of Gas, Winters 2005-6 and 2006-7
Meanwhile, demand for gas has been reduced by higher prices in recent years, but it is expected to resume an upward trend, with
more gas fired electricity generation replacing nuclear and coal fired power stations which are coming to the end of their lives on
account of both age and, for coal, tighter environmental limits. With the planned increase use of renewable sources (mainly wind)
in electricity generation, it will be essential that new gas (and, in future, “clean” coal) power stations replace much of the existing
generating plant in the coming years, so that the electrical stability of the national grid system can be maintained to guarantee
continuity of supply and prevent interruptions.
Figure 20: UK Gas Demand by Sector 1985-2005
� TheEuropeanCommissionissuedthefinalreportofitsinvestigationsinJanuary2007.
0
10
20
30
40
50
60
70
80
90
100
Winter 05/06 Winter 06/07
% o
f UK
Gas
Dem
and
Storage
BBL
Langeled
Grain LNG
Interconnector
Beach incl.Vesterled
Source: Na�onal Grid
0
20
40
60
80
100
120
140
1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005
Billi
on c
ubic
met
res
ExportsServicesOther Energy IndustriesIndustrialDomes�cElectricity Generators
Source: DTI
Page 21
Oil & Gas UK | 2007 Economic Report
The volatility of gas prices in recent years may be seen in Figure 21 below which shows the prompt (day ahead) price and forward
prices2 for the first quarters of 2006, 2007, 2008 and 2009 (the prices in the first quarter, encompassing mid-winter, are the highest
quarterly prices in any year). The reduction in prices, both prompt and forward, during the past year has been substantial, with the
commissioning of new pipeline supplies. Further import projects due on-stream in the next 12-18 months, mostly of LNG, should
help stabilise the market even further.
Figure 21: UK Wholesale Gas Prices 2004-2007
With various new import projects coming to fruition (see Figure 23), the UK is, once again, enjoying wholesale prices below those
in mainland Europe, where oil indexation of gas prices rules. Nonetheless, as may be seen in Figure 22, gas prices for commercial
and industrial customers throughout Europe have, in the main, fallen slightly during the past year. With the price of oil having risen
again in the early months of 2007, there is the prospect that all end users in the UK will soon enjoy lower prices than in the rest of
the EU, as was the case for almost all of the years since market liberalisation in Britain in the mid-1990s.
Figure 22: European Gas Prices, April 2006 - April 2007
Contrary to the normal rules of competition, though, there has been clear evidence of intervention by the authorities in France
and Spain to restrict price rises artificially; also, in Germany, it is noteworthy that small and medium users pay the highest prices
among the countries surveyed and yet, strangely, large users are much lower down the scale. It remains to be seen whether the
European Commission can succeed in driving through liberalisation of both gas and electricity markets throughout the EU and,
therefore, whether true competition in energy is allowed to develop. Security of energy supply is a major concern in the minds of
many politicians and market participants, and the concept of open markets is not seen in much of mainland Europe as a means of
achieving security of supply, in the way that it is in the UK and by the Commission.
Figure 23 lists the import projects which are either under development or have recently been completed to supply the British market.
Given that annual demand is approximately 100 billion cubic metres (bcm), this is a most impressive list of new investments. It is
also worth noting the diversity of these projects, such that the potential sources of gas to feed this capacity are many and various
(see Section 3 above, Security of Energy Supply).
2 Itshouldbenotedthataforwardpriceisnotapredictionofthepriceatafuturedate,butapricewhichmaybefixedinadvanceforthedeliveryofgas(oranyothergoodorcommodity)atadateinthefuture,inthisinstanceinthefirstquarterofeachoftheyearsshown.
0
20
40
60
80
100
120
140
160
Jan 04 Apr 04 Jul 04 Oct 04 Jan 05 Apr 05 Jul 05 Oct 05 Jan 06 Apr 06 Jul 06 Oct 06 Jan 07
Penc
e pe
r the
rm
Day aheadQ1 2005Q1 2006Q1 2007Q1 2008Q1 2009
Source: Heren Energy
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
Net
herl
ands
(Fir
m)
Aus
tria
Spai
n
Belg
ium
(Int
erru
p�bl
e)
Fran
ce Ital
y
Gre
at B
rita
in
Den
mar
k
Ger
man
y
Net
herl
ands
(Fir
m)
Fran
ce
Aus
tria
Belg
ium
(Fir
m)
Ital
y ( F
irm
)
Spai
n
Den
mar
k
Gre
at B
rita
in
Ger
man
y
Ger
man
y
Net
herl
ands
(Fir
m)
Belg
ium
(Int
erru
p�bl
e)
Fran
ce
Aus
tria
(Fir
m)
Spai
n
Ital
y (F
irm
)
Den
mar
k
Gre
at B
rita
in
€ Pe
r kW
h ex
clud
ing
tax
Apr-06
Apr-07
Small users
1 million m 3 per year
Large users
50 million m 3 per yearMedium users
10 million m 3 per year
Source: Heren Energy
Page 22
Oil & Gas UK | 2007 Economic Report
Figure 23: New UK Gas Import Projects
Furthermore, it is known that Norway is examining various options for the construction of another pipeline to deliver further gas to
either mainland Europe or Britain. The outcome is likely to be known by the end of 2007.
In a broader context, some 70% of the world’s proven gas reserves are within economic transport distance of the EU, within which
the largest markets are the UK, Germany, Italy and Spain (in descending order). Figure 24 shows possible annual flows from the
various sources where these reserves are located. Pipelines will remain the principal means by which such gas will reach the EU’s
markets, but LNG will play an increasing role and will provide an important and price sensitive degree of flexibility, thus aiding
security of supply.
Figure 24: Map of Potential Gas Supplies for Europe, 2010-20 (bcm/yr)
Name of Project Target Date(s) Capacity (bcm/year)
Langeled Pipeline (Ormen Lange) Late 2006 and 7 (see note a) 23
Bacton Interconnector Phase 1 complete 8Upgrading (note b) Phase 2 complete 7 Phase 3 late 2007 2
BBL Pipeline Complete 14
Excelerate LNG (Tees-side) Complete 4
Isle of Grain LNG Phase 1 complete 4 Phase 2 late 2008 9(Phase 3 under considera�on) Phase 3 2010? 7
Tampen Pipeline (Sta�jord - FLAGS) End 2007 10
South Hook LNG Phase 1 late 2007 11(Milford Haven) Phase 2 2009-10 10
Dragon LNG Phase 1 late 2007 6(Milford Haven) Phase 2 2010-12 3
Canvey Island LNG (planning appeal?) 2010-11? 5
TOTALS 87-123 (note c)
Notes(a) Southern leg of pipeline (from Sleipner) came onstream in October 2006; Ormen Lange field and remainder of pipeline are due in autumn 2007;(b) Original import capacity of Interconnector = 8.5 bcm per year;(c) Figure of 87 applies without Canvey Island and Phase 2 of LNG and Phase 3 of all projects;(d) Current demand in the UK is ~100 bcm per year; bcm = billion cubic metres.
EUProduc�on
145
185 -220
100 -120Norway
Nig
eria
CIS
25-60 Middle East
Libya
15-40 Central Asia
85-115
16-35
12-25
5-10
15-2
0
Egypt
Algeria
EUProduc�on
145
185 -220
100 -120Norway
Nig
eria
CIS
25-60 Middle East
Libya
15-40 Central Asia
85-115
16-35
12-25
5-10
15-2
0
Egypt
Algeria
Americas
Outlook for theUKCS in 2007
Page 2�
Oil & Gas UK | 2007 Economic Report
5. Outlook for the UKCS in 2007
UKCS Oil and Gas Production
Total production of oil and gas was 2.9 million barrels of oil equivalent per day (boepd) in 2006, which was a significant 9% decline
given the sustained, increased investment of the past two years. Delays in new projects, the impact of ageing infrastructure and
reservoir performance all contributed to this. Production in 2007-8 is forecast to increase to some 3 million boepd, as various new
projects have recently or are soon expected to come on-stream. The average decline rate from now to the end of the decade is
forecast to improve to 5% per annum, based on current investment plans.
Figure 25: UKCS Oil & Gas Production Forecast 2004-2010
Despite this slower decline rate, average production until the end of this decade is now expected to be 250,000 boepd lower than
was forecast in 2005’s survey, ref. Figure 26. Increasing costs have fed through to activity and provided the impetus to switch
investment from shorter term incremental production from existing fields to new developments with later dates for first oil / gas.
Figure 26: UKCS Progress in Production Forecasts 2004-2010
Consequently, for the first time since 2002, the forecast has deviated from the PILOT vision of producing 3 million boepd in 2010, as
shown in Figure 27. This shift is indicative of reduced confidence among investors - it now looks as though only 2.6 million boepd
will be produced in 2010.
Figure 27: UKCS Progress towards PILOT Production Target
2.0
2.5
3.0
3.5
4.0
2004 2005 2006 2007 2008 2009 2010
Mill
ion
boep
d
Possible new
Possible incremental
Probable new
Probable incremental
Sanc�oned
Source: Oil & Gas UK
0
1
2
3
4
2004 2005 2006 2007 2008 2009 2010
Mill
ion
boep
d
Actual Produc�on2006 survey2005 survey2004 survey2003 survey
Note: Excludes new explora�on and appraisal ac�vity. Source: Oil & Gas UK
1.5
2.0
2.5
3.0
3.5
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Oil & Gas UK Survey Reported Date
Mill
ion
boep
d
Source: Oil & Gas UK
Forecast produc�on in 2010 based on dated survey
Trend of survey projec�ons
Forecast produc�on in 2010 based on trend
Page 26
Oil & Gas UK | 2007 Economic Report
Oil Production
Production of oil and natural gas liquids (NGLs) fell by 10% in 2006 to 584 million barrels or 1.6 million barrels per day, significantly
less than forecast. A fifth of the shortfall was because of the delayed start of several new developments after bad weather, strikes
by divers and rig delays; some came on-stream early in 2007, while others have still to start production. However, most of the
shortfall can be attributed to lower than expected reservoir performance in existing fields, despite the increased investment seen
in 2005-6.
Figure 28 illustrates that the long-awaited improvement in the rate of decline should take effect in 2007-8 with the sizeable Buzzard
field and up to 40 other new developments coming on-stream. Although oil demand marginally exceeded indigenous production
in 2006 for the first time since 1980, the UK is expected to return to self-sufficiency in 2007-8 and still provide 90% of its needs in
2010.
Figure 28: UKCS Oil Production Forecast 2004-2010
Gas Production
In 2006, about 80 billion cubic metres of gas were produced, a 7% drop compared with 2005. This was below the forecast. Some of
this can be attributed to lower volumes of gas produced in association with declining oil production. However, higher prices (early
in the year) and mild weather (later in the year) reduced demand by 5% overall compared with 2005 and the arrival of new imports
in the autumn meant that some UKCS gas was not needed to supply the market.
From 1995 to 2003 the UK was self sufficient in gas, but became a net importer again in 2004. With sustained investment, it is still
expected that the proportion of gas demand satisfied by indigenous production could be 60% or possibly more in 2010.
Figure 29: UKCS Gas Production Forecast 2004-2010
1.2
1.4
1.6
1.8
2.0
2.2
2.4
2004 2005 2006 2007 2008 2009 2010
Mill
ion
boep
d
Possible new
Possible incremental
Probable new
Probable incremental
Sanc�oned
Source: Oil & Gas UK
120
140
160
180
200
220
240
260
280
300
2004 2005 2006 2007 2008 2009 2010
Mill
ion
cubi
c m
etre
s p
er d
ay
Possible new
Possible incremental
Probable new
Probable incremental
Sanc�oned
Source: Oil & Gas UK
Page 27
Oil & Gas UK | 2007 Economic Report
UKCS Expenditure
Total UKCS expenditure rose by £2 billion to over £11.5 billion in 2006, 10% higher than forecast only a year ago. This total comprised
about £600 million on exploring for and appraising new discoveries, £5.6 billion of capital investment to develop new fields and £5.5
billion to operate and new existing production.
Figure 30: UKCS Expenditure Forecast 2003-2010
Given that resources were already well stretched in 2005, the largest cause of increased spending in 2006 was cost inflation,
not greater activity. The sustained high oil price has increased demand for resources globally, resulting in rising costs which put
particular pressure on the economics of a mature province such as the UKCS.
Capital Expenditure
Within the main categories of the industry’s expenditure, the greatest increase occurred in capital investment which rose to £5.6
billion. This spending on field developments, including associated drilling, was 25% (£1 billion) more than in 2005. The fact that
there was no substancial increase to delivery plans over this period demonstrates the effects of cost inflation which was approaching
20%.
Figure 31: UKCS Capital Expenditure Forecast 2003-08
While the forecast reduction in 2007 may signal a return to more sustainable rates of investment after the recent rapid rises, this
is the first time since 2003 that a planned reduction in capital investment has been forecast for the year immediately following a
survey. Although investment from 2007 onwards is still higher than was forecast a year ago, this could be a significant sign that
higher costs and taxes are adversely affecting the ability of the UKCS to retain its international competitiveness and continue to
attract investment funds.
0
2
4
6
8
10
12
2003 2004 2005 2006 2007 2008 2009 2010
£ bi
llion
200
6 pr
ices
E&A
Development
Opera�ng
Source: Oil & Gas UK
0
1
2
3
4
5
6
2003 2004 2005 2006 2007 2008
£ bi
llion
200
6 pr
ices
Possible newPossible incrementalProbable newProbable incrementalSanc�oned
Source: Oil & Gas UK
Page 28
Oil & Gas UK | 2007 Economic Report
Operating Costs
Operating expenditure also rose in 2006, by 15% to £5.5 billion. A high priority in a mature oil and gas area is to maintain the
integrity of the assets; however, cost inflation was also a substantial contributory factor.
Combining the increase in operating costs with the decline in production, the unit operating cost (UOC) has risen from $5/boe in
2003 to $9-10/boe in 2006. Looking ahead, the most mature areas of the UKCS, the northern and gas dominated southern parts of
the North Sea, are expected to be the most expensive in which to operate.
Figure 32: UKCS Unit Operating Cost by Region 2005-2008
Note: “NNS”, “SNS” and “CNS” mean northern, southern and central North Sea respectively; “WoS” means west of Shetlands.
Unit Technical Costs
As mentioned above, companies operating on the UKCS have been experiencing cost inflation in the order of 20% per year throughout
2005 and 2006 which has fed through to committed spending plans and resulted in sharp increases in expenditure.
Figure 33 is an illustration of the extent of cost inflation. Oil & Gas UK’s annual survey of activity found that the cost of developing
and producing a single, new barrel of oil or gas equivalent (Unit Technical Cost or UTC) rose by 45% to $22/boe between 2005 and
2006. As expected by many, commodity prices, particularly gas, have fallen and, when combined with the higher taxes which took
effect from January 2006, the competitiveness of the UKCS is progressively being reduced.
It is predicted that this trend will continue, with the average UTC for projects coming on-stream from 2007 to 2009 rising to $25/
boe. As a result, some of the more expensive developments may not go ahead, so this estimate of future costs may, in part, correct
itself, but with the adverse consequence of less production.
Figure 33: UKCS New Developments’ Unit Technical Cost 2005-2009
2
4
6
8
10
12
14
16
2005 2006 2007 2008
$ pe
r bo
e pr
oduc
ed 2
006
pric
es
UKCS NNS SNS CNS WoS
Source: Oil & Gas UK
0
5
10
15
20
25
30
actual actual 05 survey 06 survey
$ pe
r bo
e 20
06 p
rice
s
opex / boecapex / boe
2005 average 2007-09 start-ups2006
up 45%
up 15%
$15 / boe
$25 / boe
$22 / boe
Source: Oil & Gas UK
Page 29
Oil & Gas UK | 2007 Economic Report
UKCS Drilling
Exploration and Appraisal Drilling
Despite a slow start to the year, exploration and appraisal (E&A) activity remained buoyant during 2006, supported by high oil
prices. The total number of wells drilled declined slightly to 69, but intentions to drill outweighed resource capacity. The tightness
of the rig market and a reasonably successful exploration year in 2005 saw efforts being concentrated on appraisal wells in 2006,
with 40 being drilled versus 29 exploration ones. Many planned exploration wells were delayed until 2007, but the first quarter of
this year has not seen a rebound, with nine exploration and seven appraisal wells being drilled.
Figure 34: UKCS Drilling: E&A Wells by Region 1999-2008
As Figure 34 demonstrates, drilling in 2006 was primarily targeted at well explored areas like the central and southern North Sea,
a trend which is expected to continue in 2007-8, although the recent reduction in gas prices may affect gas dominant areas of the
UKCS. Following successful exploration in 2005, there was little new exploration activity in the Atlantic margin where potential
rewards and risks are higher. It is expected, however, that exploration activity in this region will increase in 2007-8, possibly as a
result of Frontier Licence commitment deadlines. It is also likely that an increased proportion of exploration and appraisal wells will
be drilled on fallow acreage over the next two years.
Oil and Gas Discoveries
Continuing 2005’s relatively high success rate, 36% of exploration wells encountered hydrocarbons that proved to be commercial,
particularly in the southern and northern North Sea. In 2006, about 500 million boe were discovered with two accumulations
believed to be larger than 100 million boe. However the remainder of the discoveries averaged at less than 20 million boe. While
this is larger than in recent years, the downward trend in volumes discovered, as highlighted in Figure 35, is clear. Prospectivity is
just one of the factors considered in investment decisions but, in the case of the UKCS, the volumes being discovered render it less
attractive as a place to invest than in the past and when compared with newer oil and gas provinces.
Figure 35: UKCS Volumes Discovered 1965-2006
0
10
20
30
40
50
60
70
80
90
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008
No.
of E
& A
wel
ls in
cl. s
idet
rack
s
OtherAtlan�c MarginNorthern North SeaCentral North SeaSouthern Gas Basin
Source: DTI / Oil & Gas UK
forecast
10
100
1,000
10,000
1965 1970 1975 1980 1985 1990 1995 2000 2005
Mill
ion
boe
Source: Wood MackenzieNote: Volumes discovered include commercial and technical reserves.
Page 30
Oil & Gas UK | 2007 Economic Report
Prospectivity
Prospectivity refers to the likelihood of finding commercial quantities of oil and gas. In the past decade, there has been a substantial
shift in the size of UKCS prospects. Once it was normal to find accumulations of over 100 million boe, but 85% of all prospects are
now less than 50 million boe. However, there are still potentially large volumes to be discovered, particularly in the Atlantic margin /
west of Shetland, where exploration remains limited due to the depth of the waters and a lack of infrastructure, especially for gas.
Figure 36: UKCS Prospectivity (unrisked)
Some 50 billion boe of reserves have already been discovered. Assuming that similar success rates to those of recent years can
continue to be achieved, it can be extrapolated that between 4.0 and 8.2 billion boe may yet be discovered in the years ahead (see
also Figure 44 below), although current trends would indicate the lower end of this range.
Development Drilling
Oil price hurdles used by many companies for investment decisions were raised during 2005 in response to higher prices. The
volume of reserves that were economic to develop rose, therefore, and drilling of development wells increased accordingly from
2004 to 2005. However, the number then fell from 227 wells in 2005 to 211 in 2006, indicating substantial cost inflation in this
important element of capital expenditure.
Figure 37: UKCS Drilling: Development Wells 2000-2006
Although it is difficult to gauge from only three months’ data, a relatively slow start to development drilling was seen in the first
quarter of 2007 with only 43 wells drilled. However, the summer season is usually the busiest period for this and other offshore
activities and so it is to be hoped that this slow start does not signal a further reduction in the drilling of development wells,
compared with 227 in 2005 and 211 in 2006.
0-10 million boe
10-20 million boe
20-50 million boe
50-100 million boe
100-250 million boe
250-500 million boe
500+ million boe
Source: Oil & Gas UK / DTI
0
50
100
150
200
250
300
00 01 02 03 04 05 06
Num
ber
of d
evel
opm
ent w
ells
dri
lled
(incl
udin
g si
detr
acks
)
Source: DTI
Page 31
Oil & Gas UK | 2007 Economic Report
Rig Market
The theme of increasing costs also applied to E&A activity in 2006 and expenditure rose to about £600 million, with high rig rates
being a key factor. The average cost per well continued to rise to £10 million, translating into a finding cost of $3 per boe, somewhat
higher than in recent years. If predicted drilling is realised in 2007-8, spending on exploration and appraisal of new volumes is likely
to increase further. However, high charter rates may temper the demand for rigs. As illustrated in Figure 38, the average cost of
contracting a semi-submersible drilling rig in the UKCS has risen nearly eightfold and tripled for a jack-up in the last three years.
Figure 38: UKCS Rig Day Rates 2003-2007
Usage rates for both semi-submersibles and jack-ups have been at 100% since October 2006, a situation likely to continue into the
medium-term. Indeed, high charter rates are likely to pose less of a threat to drilling aspirations than availability of rigs.
Figure 39: UKCS Rig Utilisation 2003-2007
Analysis of the rig market carried out at the beginning of 2007 showed that compared to drilling aspirations, there was a shortfall
equivalent to 4.7 rig years in 2007 and 8.2 rig years in 2008. At the time of writing, monthly rig slots for the duration of 2008 were
already three quarters full and there are signs that rigs may be attracted away from UK waters, which could worsen the situation. In
addition, seismic vessel availability and processing of survey results are also emerging as significant constraints on activity.
Given the global tightness of the rig market, it is imperative that operators and rig contractors work together to use available
resources as efficiently as possible; industry participants may well have to compromise on their natural desire to drill at particular
times of the year and be more flexible in reacting to the availability of rigs at short notice. There are also differing regulatory
requirements when moving rigs across international boundaries that prevent the most effective use of available capacity.
0
50
100
150
200
250
300
350
400
Jan 03 May 03 Sep 03 Jan 04 May 04 Sep 04 Jan 05 May 05 Sep 05 Jan 06 May 06 Sep 06
Thou
sand
$ p
er d
ay
Jack-upsSemi-subs
Source: Pla�s
40
50
60
70
80
90
100
Jan 03 Jul 03 Jan 04 Jul 04 Jan 05 Jul 05 Jan 06 Jul 06 Jan 07
%
Jack-ups
Semi-subs
Source: Pla�s
Page 32
Oil & Gas UK | 2007 Economic Report
New Developments
There were 29 projects given development approval in 2006, up from 22 in 2005. They comprised 13 new field developments (six
liquids and seven gas) and 16 incremental projects on existing fields (15 liquids and one gas).
Significantly fewer fields were brought into production in 2006 than had been expected, mainly due to technical difficulties and
project delays which were largely caused or exacerbated by the pressure on resources. Given underlying decline rates of mature
fields, it is believed that one new development needs to come on-stream every 3 weeks to maintain current production rates, but
in 2006 this happened only every 5 weeks. Half of the new developments used subsea technology, an approach which has grown in
popularity as technology has advanced and as a means to reduce infrastructure requirements and hence development costs.
Figure 40 summarises the new fields that are expected to come on-stream in 2007 and 2008, 70% of which will be subsea
developments. As has been the case in recent years, the vast majority are located in the southern and central North Sea.
Figure 40: UKCS Field Developments 2007-2008
Field Name Loca�on Field Type Operator Development Status Development TypeProduc�on StartUp
Recoverable Oil & Gas million boe
Affleck CNS Oil & Gas Maersk Oil & Gas Under Development Subsea 2007 43Barnacle NNS Oil Energy Development Partners Probable Development Extended Reach 2007 3Blane UK CNS Oil Talisman Under Development Subsea 2007 26Brenda CNS Oil Oilexco Under Development Subsea 2007 34Brodgar & Callanish CNS Oil & Gas ConocoPhillips Under Development Subsea 2007 132Buzzard CNS Oil Nexen Onstream Fixed Pla�orm 2007 557Caravel SNS Gas Shell Probable Development Fixed Pla�orm 2007 24Cavendish SNS Gas RWE Dea Under Development Subsea 2007 21Chestnut CNS Oil Venture Produc�on Under Development FPSO 2007 7Chiswick SNS Gas Venture Produc�on Under Development Fixed Pla�orm 2007 29Davy East SNS Gas Perenco Under Development Subsea 2007 4Donan Redevelopment CNS Oil Maersk Oil & Gas Onstream Subsea 2007 71Duart CNS Oil Talisman Under Development Subsea 2007 5Enoch - UK CNS Oil & Gas Talisman Under Development Subsea 2007 11Fiddich CNS Gas/condensate Talisman Probable Development Subsea 2007 20Garrow SNS Gas ATP Oil & Gas Under Development Subsea 2007 7Grove SNS Gas/condensate Newfield Explora�on Under Development Fixed Pla�orm 2007 18Kelvin SNS Gas ConocoPhillips Probable Development Fixed Pla�orm 2007 11Loirston NNS Oil & Gas ExxonMobil Under Development Extended Reach 2007 3Magnus NW NNS Oil BP Under Development Extended Reach 2007 5Maria CNS Oil & Gas BG Under Development Subsea 2007 35Mimas SNS Gas ConocoPhillips Under Development Subsea 2007 7Minke SNS Gas Gaz de France Probable Development Subsea 2007 8Nevis West Beryl NNS Oil & Gas ExxonMobil Under Development Subsea 2007 7Nicol CNS Oil Oilexco Under Development Subsea 2007 13Saxon CNS Oil Petro-Canada Probable Development Subsea 2007 11Tethys SNS Gas ConocoPhillips Under Development Subsea 2007 12Thurne SNS Gas Tullow Oil Under Development Subsea 2007 2Tweedsmuir CNS Oil Talisman Under Development Subsea 2007 76Wenlock SNS Gas ATP Oil & Gas Under Development Subsea 2007 10West Franklin CNS Gas/condensate Total Under Development Extended Reach 2007 34Wood CNS Oil & Gas Talisman Under Development Subsea 2007 13
Curlew C CNS Oil & Gas Shell Probable Development Subsea 2008 8E�rick CNS Oil Nexen Under Development FPSO 2008 35Jacqui CNS Oil & Gas ConocoPhillips Probable Development Subsea 2008 16Rita SNS Gas E.ON Ruhrgas Probable Development Subsea 2008 4Shamrock SNS Gas/condensate Shell Probable Development Fixed Pla�orm 2008 19Starling CNS Gas/condensate Shell Under Development Subsea 2008 32Topaz SNS Gas RWE Dea Probable Development Subsea 2008 6Wissey SNS Gas Tullow Oil Probable Development Subsea 2008 4
Page 33
Oil & Gas UK | 2007 Economic Report
-
5
10
15
20
25
30
35
40
1999 2000 2001 2002 2003 2004 2005 2006
%
Propor�on of total produc�on
Propor�on of total capital invested 38%
16%
Source: Wood Mackenzie
UKCS Players and Commercial Activity
The importance of encouraging a diverse range of new companies into a mature province is highlighted in Figure 41, which shows
the growing and now very significant contribution that new entrants have made since 1999, both in terms of expenditure and
production.
Figure 41: New Entrants’ Contribution to Production & Investment 1999-2006
The growth of this sector is not guaranteed though, especially if asset trading with new entrants falls. Asset trading dropped
dramatically in 2006 with only 17 deals reported by year end, half the number seen in 2005. This is a historic low and, significantly,
for the second year running no new entrants were attracted into the UKCS.
Figure 42: Buyers of UKCS Assets 1995-2006
The active trading of assets is a strong reflection of commercial competitiveness. High oil and gas prices have undoubtedly made
initiating the decision to sell more difficult. However, uncertainty regarding the fiscal and regulatory treatment of decommissioning
is cited by all deal parties as a significant barrier to trading assets. Prompt action needs to be taken to address the fiscal and
regulatory issues, particularly to provide certainty on the future tax treatment of decommissioning costs and to avoid the regulatory
framework for decommissioning from becoming a barrier to the sale or purchase of assets.
Figure 43: UKCS Asset Transfer and Oil Price 1993-2006
0
20
40
60
80
100
120
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Num
ber
of a
sset
dea
ls
New entrantsExis�ng smallExis�ng large
Source: Wood Mackenzie
0
500
1000
1500
2000
2500
3000
1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Mill
ion
boe
0
10
20
30
40
50
60
70
$ /
bbl
Global MergersOtherOil price
Source: Wood Mackenzie
Industry Perspectives
Page 3�
Oil & Gas UK | 2007 Economic Report
6. Industry PerspectivesStewardship of the UK’s Oil and Gas Resources
The UK still has substantial oil and gas reserves remaining despite having produced just over 36 billion boe over the last 40 years.
Based on the latest DTI figures, Oil & Gas UK estimates that there are somewhere between 16 and 25 billion boe still to be recovered,
with current trends delivering about 20 billion boe.
It should be noted that the “25 billion boe” figure is based on DTI’s mid-case view which still adopts a conservative approach to
ultimate recovery rates. DTI’s high case implies that there could be up to 39 billion boe still to be recovered which provides an
indication of the overall potential of the UKCS.
Figure 44: UKCS Projected Reserves and Resources
Figures 45 and 46 show the overall oil and gas reserves/resources split by sector of the UKCS. Current projections suggest the
overall split is weighted 66% oil and 34% gas.
Almost half of the remaining reserves are located in the central North Sea, followed by around 25% to the west of the Shetlands
and slightly over 15% in the northern North Sea. The southern North Sea and the Irish Sea complete the picture with 10% and 2%
of the total, respectively.
Figure 45: UKCS Oil Reserves and Resources by Sector
-5
0
5
10
15
20
25
Billi
on b
oe
Exploration (yet to find)
Produced 1.1 billion boe in 2006
Sanctioned investments / in production
Brownfields
Undeveloped discoveries
4.0 - 8.2
2.4 - 4.0
1.5 - 4.5
Source: Oil & Gas UK 1.1.07
8.1
57% Central North Sea
17% Northern North Sea
0% Southern North Sea
1% Irish Sea
25% West of Shetlands
Source: Oil & Gas UK / Wood Mackenzie
Note: excludes West of Scotland
32% Central North Sea
15% Northern North Sea
29% Southern North Sea
5% Irish Sea
19% West of Shetlands
Source: Oil & Gas UK / Wood Mackenzie
Note: excludes West of Scotland
Figure 46: UKCS Gas Reserves and Resources by Sector
Page 36
Oil & Gas UK | 2007 Economic Report
During 2006, Oil & Gas UK commissioned consultants Wood Mackenzie to update a previous study, in 2004, on the economic life
of infrastructure and whether the UK will be able to develop fully its remaining oil and gas reserves. The outcome from that study,
combined with data provided by DTI, has helped Oil & Gas UK to understand the size of the opportunity from yet-to-find and
undeveloped resources and its impact on the life of transport infrastructure. The main conclusions of the study are:
• more needs to be done to maximise UKCS recovery. As indicated above, recent trends project the future recovery of
20 billion boe, but, if the industry can improve its investment efficiency, an additional five or more billion boe could
be developed which means there is a significant prize to aim for;
• there is an estimated 4 billion boe still to be recovered from currently producing fields (“brownfields”) in addition to
the 1 billion boe of incremental projects already planned by companies;
• unless activity is sustained, some 45% of infrastructure could be decommissioned by 2020; however, this could
be delayed by 10-15 years in many systems, with an appropriate fiscal and regulatory regime if investors remain
sufficiently confident.
Figure 47: Tale of Two Futures (2006 data)
Inevitably with maturity, the existing producing base is declining rapidly and would only provide 8% of the nation’s oil and gas in
2020. Current investment plans should lead to double this proportion. However, if the industry and government together rise to
the challenge and ensure that investment is sustained, the UKCS has a long and productive future ahead of it and could still be
providing some 40% of the nation’s oil and gas requirements in 2020, a major prize and one which would significantly aid security
of supply (see Figure 47).
0
1
2
3
4
5
2006 2008 2010 2012 2014 2016 2018 2020
Mill
ion
boep
d
Oil and Gas Demand
The Be�er Future40% of Na�on's demand in 2020
Exis�ng Produc�on Base8% of Na�on's demand in 2020
Source: Oil & Gas UK
Page 37
Oil & Gas UK | 2007 Economic Report
International Competitiveness – Fiscal and Regulatory Environment
Tax rates for oil and gas production now range from 50% - 75% since the latest increase in the Supplementary Charge to Corporation
Tax in January 2006. Coupled with the frequent increases and adjustments to the fiscal regime in the last five years, there is a
heightened sense of fiscal uncertainty when considering the UK from an investor’s perspective. The industry is seeking a more
competitive regime which provides certainty for both existing and future investment, as well as with respect to decommissioning
activities.
This is a global industry and so new ways will have to be found to create an advantage over other oil and gas provinces. It is
important, therefore, that the fiscal and regulatory regime reflects both the UKCS’s competitive position internationally and its
maturity. It is widely accepted that the tax burden will have to be reduced with time, if the maximum recovery of reserves is to
be achieved. Higher rates of taxation raise economic thresholds for investment and lead to less activity and lower recovery in the
longer term.
There are signs that the government is recognising some of the limitations of the current regime. In December 2005, it announced
its intention to start discussions with the industry to examine the wider structural issues of the fiscal regime, including the lifespan
of Petroleum Revenue Tax (PRT), decommissioning and overall competitiveness. It is clear that all parties wish to see the maximum
recovery of oil and gas and the discussion rightly centres on how this may best be achieved. This dialogue is continuing and the
industry is currently in the process of responding to the latest consultation document issued by the Treasury in Budget 2007 on the
future of UKCS taxation.
Furthermore, in the most recent budget, it was announced that, from 1st July 2007, previously decommissioned fields that are
redeveloped will no longer be liable for PRT. This measure should encourage investors to consider the possibility of reactivating
abandoned fields and use new technology to recover untapped reserves. It is a clear demonstration of how the removal of a tax
will promote investment, generate new production and, subsequently, greater tax revenues.
For the UKCS to attract investment, the investor must consider a range of factors in which the fiscal regime plays an important role.
Many of the criteria which are routinely considered are shown below:
i) Economic measures – include Net Present Value (NPV) and Expected Monetary Value (EMV) which are both post tax
measures and sensitive to changes in tax rate;
ii) Portfolio fit (e.g. global or regional);
iii) Strategic fit (e.g. niche / independent / major);
iv) Materiality – considers the size, value (post-tax) and impact of the opportunity; the size of new discoveries in the
UKCS is typically small and may demand disproportionate company resource to enable development;
v) Timing and longevity of investments – oil and gas is, inevitably, a long term industry, with investments typically
taking 2-5 years to come on-stream and producing for 15 years or more; investments are tested against long term
perceptions of price, combined with an assessment of regulatory and fiscal risks;
vi) Risk exposure – technical aspects, costs, funding, price, exchange and interest rates, are all risks borne by the investing
companies; the risks that a government can influence are in the fiscal, regulatory and political environment.
The North Sea is one of the most expensive oil and gas regions in the world, given the water depths and harsh marine environment;
costs have risen sharply in the last two to three years. The UKCS, as the most mature area of the region, has to compete with other
less mature and less costly oil and gas provinces which offer investors some attractive choices when looking where to invest. In the
last 10 years, the success rate and size of fields discovered in UK waters have diminished significantly (i.e. prospectivity has fallen
materially). Discoveries now are routinely small, typically averaging at 20 million boe or less. It is now both more difficult and more
expensive to find oil and gas than it was 10 or 20 years ago. The challenges set by geology at this late stage in the life of the UKCS
have an important effect on competitiveness compared with other, less mature oil and gas regions. An interesting comparison of
maturity is given in the map below which presents a picture of how much drilling has been undertaken in the central and northern
North Sea in British and Norwegian waters; the UK sector has clearly been more heavily explored. Norway also has the advantage
of other, unexplored prospects in the waters of the Norwegian and Barents Seas further north. Overall, Norway enjoys appreciably
better prospectivity.
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Oil & Gas UK | 2007 Economic Report
Figure 48: UK & Norway wells drilled 1965 -2003
There is a range of non-fiscal measures which is also being undertaken by DTI and the industry in conjunction with Oil & Gas UK to
help promote the investment and activity. These include the following, for which more details may be found in Appendix B of this
report:-
(i) improving access to data
(ii) removing barriers to entry
(iii) promoting good stewardship of assets
(iv) facilitating access to infrastructure
(v) encouraging positive commercial behaviour
(vi) promoting a strong supply chain.
Despite all of the challenges, there are major strengths which make the UKCS a good place to conduct business: political stability,
low barriers to entry, extensive infrastructure, a strong supply chain and a highly skilled workforce. There are still significant
opportunities to be pursued, not least because the UK has developed as an international centre for oilfield goods and services;
these have grown rapidly over the last decade and now constitute a major exporting industry. These strengths provide secure
foundations for building the right future for this industry.
Source: Norsk Hydro / Petrobank (December 2003)
Page 39
Oil & Gas UK | 2007 Economic Report
0
5
10
15
20
25
30
35
40
45
50
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Q12006
Q22006
Q32006
Q42006
ROCE
%
0
10
20
30
40
50
60
70
80
Oil
Pric
e (£
/bbl
) and
Gas
Pri
ce (p
/th)
Pre-tax ROCEPost-tax ROCEOil PriceGas Price
Source: Office of Na�onal Sta�s�cs / Oil & Gas UK
Annual Quarterly
UKCS Rate of Return
Oil and gas extraction is a capital intensive industry, where significant expenditure has to be made at all stages of a development,
from exploration and appraisal drilling through production to decommissioning. Because of the very nature of the projects, they
have high degrees of risk attached to them and, once an investment has been made, very large “sunk” costs. These risks mean that
investors look for better returns than in other industries and this increasingly affects oil and gas provinces as they mature.
The Office of National Statistics (ONS) regularly publishes details of the rates of return for the oil and gas sector. This profitability
measure is more usually referred to as “Return on Capital Employed” (RoCE). It is an accountancy calculation of the ratio of
earnings before tax and interest expressed as a percentage of capital employed. ONS follows the convention of reporting RoCE
pre-tax. However, in so doing, it fails to highlight that oil and gas extraction is taxed at much higher rates (50% - 75%) than other
businesses. Investors are more concerned with post-tax returns, as the recent pressure for a general reduction in corporate tax
rates demonstrates, to which the government responded in March 2007’s Budget by lowering the rate of Corporation Tax from 30%
to 28%, but not for the offshore oil and gas industry.
Figure 49: UKCS Rate of Return (Pre- and Post- Tax) 1995-2006
The above chart compares ONS RoCE, both pre-tax and post-tax, for the last twelve years (note the change of scale from annual to
quarterly for 2006). Pre- and post-tax RoCEs initially rose last year, but have since declined rapidly following lower than expected
production, higher costs and falling gas prices. The pressure on margins, particularly for gas, has started to raise fresh concerns
about the longer term competitiveness of the province and its exposure to falling commodity prices, a point which the industry
highlighted when the Supplementary Charge on Corporation Tax was increased in January 2006. Based on these new realities, in
March 2007’s Budget, HM Treasury significantly reduced its projections of UKCS tax revenues compared with its previous forecast.
Oil & Gas UK has fundamental reservations about the use of RoCE as a method for determining profitability. Economic measures
– like Net Present Value (NPV) or Expected Monetary Value (EMV) – are the ones which drive investment, rather than accountancy
measures such as RoCE. Furthermore, Oil & Gas UK considers that the ONS understates the enormous scale of capital investment in
the UKCS, thus leading to an over estimation of the RoCE. Interestingly, the ONS recognises this on its web-site, expressing concern
about the use of this measure for the industry.
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Oil & Gas UK | 2007 Economic Report
Meeting the Decommissioning Challenge
Over the next two decades, the industry will begin to decommission many of the installations that have been producing oil and
gas during the past 30-40 years. It is a complex process, representing a considerable challenge on many fronts and encompassing
technical, economic, environmental, and health and safety issues. There are approximately 470 installations to be decommissioned,
including very large ones with concrete sub-structures, small, large and very large steel platforms, and subsea and floating equipment,
the vast majority of which will have to be totally removed to the shore for dismantling and disposal. Some 10,000 kilometres of
pipelines, 15 onshore terminals and around 5,000 wells are also part of the infrastructure planned to be gradually phased out.
Figure 50: UKCS Decommissioning Profile 2006-2030+
An indicative profile of the installations to be decommissioned is shown in Figure 50. However, the precise timing of decommissioning
is highly uncertain and has, in a number of cases, already been delayed from what is shown. Decommissioning timing will be
influenced by a range of factors including:
• Long-term trends in oil and gas prices – which will determine whether it remains economic to keep a field in operation;
• Long-term certainty of both fiscal and regulatory regimes – which will influence the future investment environment;
• Increased recovery – from existing fields, new exploration and tie-back of new fields, which will extend the productive life
of these assets and infrastructure;
• Reduction of decommissioning cost – through greater co-ordination with the supply chain and a more systematic approach
across the industry;
• Technical innovation - which will increase oil and gas recovery, extend the life of many existing facilities and ultimately
reduce the costs of decommissioning.
The costs involved in decommissioning infrastructure are variously estimated to be in the range of £15 - £20 billion which reflects
the many uncertainties, including the total extent of decommissioning liabilities. Oil & Gas UK’s own activity survey of members in
late 2006 places decommissioning costs at £12 billion (2006 prices) for existing assets, £3 billion higher than estimated four years
ago. It is expected that additional new investment, over and above current plans, will increase decommissioning activity by a
further £3 billion, bringing the total to around £15 billion. It should also be noted that, during the last four years, decommissioning
has generally been delayed by about two years, as a result of the increase in oil prices and improved projections of recovery.
Figure 51: Evolution of UKCS Decommissioning Costs, Oil & Gas UK Survey 2002-2006
0
5
10
15
20
25
30
35
2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029Source: DTI
Num
ber
of in
stal
la�o
ns
OtherSubseaSmall SteelLarge Steel & Concrete
0
2
4
6
8
10
12
14
2006 2011 2016 2021 2026
Cum
ula�
ve s
pend
£ b
illio
n 20
06 p
rices
2006 Survey
2002 Survey
Source: Oil & Gas UK
Cost decrease due to:- technical cost reduc�on- reduced regulatory risk and uncertain�es
Asset life extension achieved by:- increasing resource base- maximising recovery (at op�mum pace)- cost decrease- reduced fiscal risk and uncertain�es- high oil prices
Page 41
Oil & Gas UK | 2007 Economic Report
If industry succeeds in bringing further reserves into production from both existing and new fields in the longer term, decommissioning
could be delayed by 10-15 years in many infrastructure systems (see an example for a major hub in Figure 52 below). Extending
the life of infrastructure allows more reserves to be recovered from both existing fields and any developments arising from new
exploration activity. Once infrastructure is removed, nearby exploration potential becomes very expensive to develop, thus reducing
ultimate recovery from the UKCS.
Figure 52: Example of the life extension of a major gas hub
Whilst for most fields decommissioning is not an imminent activity, it already has had an impact on the economic life of the
UKCS as a whole. There are profound concerns about whether the current requirements regarding financial securitisation of
decommissioning liabilities and their fiscal treatment are creating an unnecessarily costly and rigid framework in which to operate.
This is hindering and even preventing the sale of assets by existing investors to new investors, thereby reducing commercial activity,
restricting the number of new entrants and, ultimately, reducing the recovery of the UK’s oil and gas reserves.
It is increasingly recognised that changes are required to the regulatory framework and fiscal treatment of decommissioning
liabilities, if the UK is to continue to attract new entrants and extend the economic life of the province. Under the auspices of PILOT
(the government - industry forum chaired by the Secretary of State), discussions are continuing between the industry and the DTI,
HM Revenue & Customs and HM Treasury on a series of necessary proposals for regulatory and fiscal change. It is to be hoped that
these will be successful.
Prod
uc�o
n
-
100
Brownfield
Exis�ng Produc�on
E&A +New Developments
Economic cut off point
0
20
40
60
80
120
2006 2010 2015 2020 2025 2030
Source: Oil & Gas UK
Page 42
Oil & Gas UK | 2007 Economic Report
UKCS Contribution to Delivering Environmental Targets
Figure 53: UK Energy Intensity 1970-2005
As the economy has shifted from reliance on manufacturing to services and energy efficiency has improved, less energy has been
required per unit of output. Overall, the energy intensity of the UK’s output has halved since 1970, with reductions in coal (82%)
and oil (63%) intensity leading the way. However, the use of natural gas has increased dramatically with the volume of gas consumed
in the creation of every £1 of output having almost tripled since 1970. The use of renewables and hydro-electricity in output
creation has more than quadrupled since 1970, but the starting point was so small that even in 2005 only 2% of energy used per £1
output was attributable to this type of energy.
The UK is committed under the Kyoto Protocol and the EU’s burden sharing agreement to reduce greenhouse gas emissions by
12.5% in 2008-12 (as an annual average) compared with its emissions in 1990. Furthermore, it has set its own target of reducing
carbon dioxide (CO2) emissions by 20% between 1990 and 2010. As figure 54 below shows, the UK is already meeting the Kyoto
objective for emissions (comprising a basket of six greenhouse gases).
Figure 54: UK Greenhouse Gas Emissions 1990-2006
Gas is much less carbon intense than coal or oil and it is also much more thermally efficient in power generation, so the switch to
gas for electricity production since 1990 has enabled the UK to record a reduction in CO2 emissions despite a 10% increase in overall
energy demand. This major contribution to efforts to reduce emissions of greenhouse gases is also reflected in the emissions
intensity of energy consumption which fell by 23% between 1990 and 2006.
Although CO2 emissions have recently been seen to rise, this probably resulted, in the main, from greater use of coal fired power
generation during 2005 and 2006, when higher gas prices made coal more economic. Now that gas prices have fallen sharply and
with the closure of many coal fired power stations due between 2008 and 2015 on account of the Large Combustion Plant Directive,
it is likely that gas will resume its previous growth as a fuel for power production. Its share of electricity generation is forecast to
rise from 35% in 2005 to possibly as much as 60% in 2020, and so it can continue to help reduce the UK’s emissions of CO2, but
depending on the mixture of gas, nuclear and, perhaps, “clean coal” generation capacity that is built to replace older coal fired and
nuclear plant.
0.000
0.005
0.010
0.015
0.020
0.025
0.030
0.035
0.040
1970 1974 1978 1982 1986 1990 1994 1998 2002
Tonn
es o
il eq
uiva
lent
per
£ G
DP
2005
pri
ces
0.0
0.2
0.4
0.6
0.8
1.0
1.2
Tonn
es C
arbo
n pe
r To
nne
oil e
quiv
alen
t con
sum
p�onCoal Oil
Gas NuclearOther Emissions Intensity
Note: 'Other' includes, hydroelectric, renewables and net electricity imports Source: DTI / ONS
0
100
200
300
400
500
600
700
800
900
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
Mill
ion
tonn
es (C
arbo
n di
oxid
e eq
uiva
lent
)
Carbon dioxide emissionsBasket of greenhouse gas emissionsDomes�c carbon dioxide target by 2010Kyoto target by 2008-2012
Source: DEFRA
Page 43
Oil & Gas UK | 2007 Economic Report
The EU’s Emissions Trading Scheme (EU ETS) is now in the third and final year of Phase I. This first phase was always intended as a
trial, before the more important Phase II which lasts from 2008 until 2012, the same as the Kyoto period. It is clear that too many
allowances were allocated by Member States in Phase I, although not in the UK, such that the traded price of a Phase I allowance
has crashed (see Figure 55). However, the European Commission has been taking a much stricter line with Member States’ plans for
Phase II (these plans limit the emissions of CO2 permitted by the industries participating in the EU ETS for all Member States). As a
result, the traded value of a Phase II allowance, ahead of its commencement, has been in the range €15-20 per tonne.
Nonetheless, the UK would appear to be shouldering its full share of the burden of the scheme and, by comparing practices across
the offshore oil and gas industry, it seems clear that the UK is implementing the requirements of the scheme in a more stringent
manner than is to be found elsewhere in the EU.
Figure 55: EU Carbon Allowance Prices April 2005 – March 2007
The EU is now considering a third (and possibly further) phase(s) for the EU ETS starting in 2013. It is highly likely that this will proceed,
whether there is another international agreement to follow the Kyoto protocol or not. Among the questions being considered in this
review are the length of the phase(s), whether an overall EU limit should be set as the starting point for Member States (currently it
is built upwards from Member States’ plans), methods for allocating allowances, harmonisation of implementation across Member
States, whether other greenhouse gases should be brought into the scheme and the like. This should lead to legislative proposals to
amend the Directive being tabled in the second half of 2007, with amendment taking place so that Member States may implement
the changes during 2010 in readiness for 2013.
It will be essential that carbon capture and storage is recognised under Phase III, if it is to take its place as a means for managing
carbon emissions.
0
5
10
15
20
25
30
35
Jan-
05
Feb-
05
Mar
-05
Apr
-05
May
-05
Jun-
05
Jul-0
5
Aug
-05
Sep-
05
Oct
-05
Nov
-05
Dec
-05
Jan-
06
Feb-
06
Mar
-06
Apr
-06
May
-06
Jun-
06
Jul-0
6
Aug
-06
Sep-
06
Oct
-06
Nov
-06
Dec
-06
Jan-
07
Feb-
07
Mar
-07
Apr
-07
€/to
nne
CO2
2005 EUAs 2006 EUAs 2007 EUAs 2008 EUAs 2009 EUAs Source: John Hall Associates
2008-12: Phase II
2005-07: Phase I
Page 44
Oil & Gas UK | 2007 Economic Report
Carbon Capture and Storage and Enhanced Oil Recovery
An increasing awareness of climate change, with CO2 being seen as its principal cause, has led to greater interest in carbon
abatement technologies. This is also driven by the provisions of the Kyoto protocol. Carbon capture and storage (CCS) is one
such technology which has the capability to reduce substantially CO2 emissions created by the use of fossil fuels. It involves three
separate stages: capture, transport and storage. The CO2 from large industrial or power generation sources is first captured (pre- or
post-combustion) using a combination of physical and chemical processes, then transported to a storage location and finally stored
in a geological structure such as suitable, mature oil or gas reservoirs, or an aquifer.
Europe is believed to have extensive CO2 storage capacity, predominantly located beneath and around the North Sea. The British
Geological Survey has estimated the potential storage capacity under the whole of the North Sea at around 20 billion tonnes of
CO2 in oil and gas fields, with an additional 20–70 billion tonnes of CO2 in confined aquifers. This compares with the UK’s current
emissions of around 560 million tonnes of CO2 per year. CCS has, therefore, the potential to enable the production of low carbon
electricity and provide an environmentally attractive method of disposing of CO2.
In the autumn of 2006, the Stern Review of the Economics of Climate Change was published. The review recognised the
importance of CCS and stated that it is essential to maintain the role of coal in providing secure and reliable energy. The 2007
Budget responded to the Stern Review and set out the next stage in the Government’s strategy for tackling climate change both
domestically and globally. The British government declared its intention to finance the first full scale demonstration of CCS, in
order to raise its profile; in the recently published Energy White Paper, a competition is planned for the autumn of this year.
In addition, DTI has launched an invitation to tender for a study into the development of CO2 transport and storage infrastructure in
the North Sea. Final results of this work will be reviewed by the North Sea Basin Taskforce and reported to Norwegian and British
Ministers in July 2007.
Currently, CCS is not legally permitted under the sea; CO2 is officially designated a waste product and injection beneath the seabed
is only allowed in international law if it is associated with enhanced oil recovery (EOR). There are two governing conventions:
i) the London Convention has been amended under Annex 1 of the protocol to allow CCS in subsea geological structures;
this amendment was approved in November 2006 and entered into force on 10th February 2007 – related regulatory
and legal impediments to CCS will be removed within 2 years;
ii) the OSPAR Convention, covering the waters of the north east Atlantic, currently prohibits CCS without EOR and,
therefore, this significant hurdle also needs to be overcome for CCS to proceed; the necessary work is in hand and,
although the timing of its conclusion remains uncertain, it would appear to be making steady progress.
Figure 56: Carbon Capture and Storage
Source: National Environment Research Council
Page 4�
Oil & Gas UK | 2007 Economic Report
It should be noted that various other methods of primary and secondary EOR have been employed by the offshore oil and gas
industry for many years and so it is important to remove these legal obstacles promptly, if EOR using CO2 is to be applied to the
UKCS. As time passes and the depletion of fields progresses, the opportunities for further EOR diminish and become less and less
attractive. In addition, the fields in UK waters most suitable for CO2 injection lie in the southern North Sea – a gas producing area
– thus eliminating any need for EOR applications.
In the longer term, for CCS to become a workable method of carbon abatement there are other, major issues which must be
addressed. Principally, the market price of carbon would need to increase from its current value of €15-20 per tonne in Phase II of
the EU ETS. It would require a price several times higher than this before projects using CCS become commercial.
In the current market, if CCS is to be used to enable the generation of low carbon electricity, there needs to be the same economic
encouragement as is provided for renewables. This includes renewable obligation certificates (ROCs) and levy exemption certificates
(LECs) which prove the reduced carbon associated with the electricity produced. At least eight major CCS projects are currently
being considered in various parts of the UK, encompassing some 7,000MW of electrical generating capacity. In addition to higher
prices of traded carbon and consistency with renewables, there should also be recognition within the EU ETS for low carbon sources
of electricity with an allocation of credits equal to carbon abated.
The 2007 Budget also initiated a consultation on the “change of use” of offshore oil and gas fields which may in future be converted
to CCS or gas storage. Discussions are continuing, but it is clear that the existing fiscal regime presents a range of barriers to such
re-use of old assets. These will have to be overcome, if the ultimate potential of the UK’s offshore fields and their associated
infrastructure is to be realised.
Figure 57: UK Proposed Carbon Capture and Storage Projects
Kingsnorth
Teesside
Ha�ieldFerrybridge Killingholme
Immingham
Tilbury
Source: CCS Associa�on
Appendix
Page 47
Oil & Gas UK | 2007 Economic Report
7. Appendix
A. UKCS Fiscal Regime
The offshore oil and gas industry is the highest taxed industry in the country. Fields developed since March 1993 are taxed at 50%,
being liable for both Corporation Tax (CT) at 30% and a Supplementary Charge (SCT) at 20%. The marginal tax rate rises to 75% on
fields developed before 1993, these also being liable for Petroleum Revenue Tax (PRT) at 50%.
Figure 58: Marginal Government take from fields ranges from 50% to 75%
Corporation Tax (CT) and Supplementary Charge (SCT)
The combination of SCT and CT mean that all new field developments are taxed at a rate of 50%.
Oil and gas exploration and production companies are subject to CT which is applied to company profits at a rate of 30%. It should
be noted that the offshore oil and gas industry has been excluded from the general reduction in the rate of CT from 30% to 28%,
applicable from April 2008, announced in 2007’s Budget in March.
SCT was raised to 20% from 1 January 2006. It was originally introduced at a rate of 10% in 2002’s Budget which also saw the
introduction of 100% First Year Allowances for UKCS capital expenditure in recognition of the higher tax rate. Since the introduction
of 100% First Year Allowances, all capital costs are effectively tax deductible as incurred, with the exception of long life assets which
secure a 24% First Year Allowance and 6% of the remainder on a reducing balance basis.
Taxable profits derived from the extraction of oil and gas from the UKCS are also “ring fenced” so that losses from other activities
cannot be offset against these ring fenced profits. Stringent rules are also applied to ensure that only interest relating to UKCS
projects is deductible within the ring fence. However, the taxable profit for SCT differs from CT in that finance costs are not
deductible.
Petroleum Revenue Tax (PRT)
PRT of 50% raises the marginal rate of tax to 75% for many oil and gas fields.
PRT is applied on all fields which received development consent before 16 March 1993 and to tariff arrangements existing prior to
9 April 2003 relating to pipeline systems and other facilities which in some part service a PRT paying field. Tariff contracts arranged
on or after this date are exempt from PRT, as addressed in the Finance Act 2004. PRT is applied to profits, field by field, in six-month
chargeable periods. If losses arise, the ability to surrender losses to other fields is extremely limited.
PRT is deductible for CT and SCT. Capital and operating costs are also deductible. No deduction is allowed for interest, but most
capital incurred pre-payback (see below) qualifies for an additional deduction of 35% (uplift). As most fields subject to PRT are past
payback, the significance of this relief is now very limited.
CT, SCTEffec�ve Marginal Tax Rate 50%
Post-1993 fields
CT, SCT & PRTEffec�ve Marginal Tax Rate 75%
Ring fenced pre-1993 fields
Source: Oil &Gas UK
Page 48
Oil & Gas UK | 2007 Economic Report
Payback is the period in which total cumulative income exceeds total cumulative expenditure. This period not only determines the
cut-off for uplift, but also dictates the number of six-month periods for which safeguard applies.
Safeguard was introduced as a safety net for the benefit of the less profitable fields, essentially to ensure that, in the early years
of a field’s life, the PRT cannot exceed an amount that would reduce the participants’ after-tax profit below a minimum return on
investment in the field. It limits PRT in each six-month chargeable period to 80% of the excess profits over 15% of cumulative capital
which has qualified for uplift. It applies to the period from the start of production to the period of payback plus half as long again.
It will not apply if it calculates PRT in excess of the “normal” calculation.
An “Oil Allowance” can be applied to fields with development consent on or before 31 March 1982 which makes the first 250,000
tonnes per six-month period, up to a cumulative total of 5 million tonnes, PRT free. For southern fields the amounts are 125,000
and 2.5 million tonnes and for all other taxable fields 500,000 and 10 million tonnes respectively.
A “Tariff Receipts Allowance” is available for some income streams. This makes the first 250,000 tonnes of throughput for each
user field per six-month period PRT free.
Gas sold under contracts entered into before 30 June 1975 is exempt from PRT.
As mentioned above, new tariff business for transportation, processing, and other services provided through the use of UKCS
infrastructure which is transacted under contracts entered into on or after 9 April 2003 will be exempt from PRT, provided the
infrastructure is used in relation to:
a) A field receiving development consent on or after 9 April 2003; or
b) An existing field using a new evacuation route, but only if that field has not to date made use of non-field assets,
which have qualified for PRT relief.
While the exemption covers new tariff business contracted on or after 9 April 2003, it only applies to income and expenditure
received and incurred under such contracts since 1 January 2004.
Page 49
Oil & Gas UK | 2007 Economic Report
B. Recent Initiatives to Promote the UKCS
DTI and Oil & Gas UK are working closely together through PILOT to encourage a positive business environment which can help
maximise recovery of oil and gas. A number of initiatives are underway, directed at the objectives outlined in the table below. These
are necessary conditions that, together with an appropriate fiscal and regulatory regime, will enhance the UKCS’s competitiveness
and its ability to attract international investment.
Objective Initiative Progress / Success
Improving Access to Data • CDA, a subsidiary of Oil & Gas UK,
manages two data services that
have become indispensable tools for
any company currently working or
planning to work in the UKCS:
- DEAL (www.ukdeal.co.uk) – a
free, public, web-based service
to promote and facilitate access
to data and information for the
exploration and production of oil
and gas in UK waters.
- CDA DataStore – provides
digital data to subscribers on
more than 10,000 wells drilled
on the UK Continental Shelf.
• DEAL facilitates access for thousands of
regular users to several million items
of data for the UKCS. Developments
underway will enhance its value to users
through significantly increased licence data
functionality and ongoing initiatives to
further improve data quality.
• The CDA DataStore has 46 members and
about 500 users who download digital well
log data and scanned well reports via the
internet from anywhere in the world. An
equivalent service for seismic data is at an
advanced stage of planning.
Removing Barriers to Entry • Fallow Initiative – places acreage
which has been inactive for some time
into the hands of companies willing to
use it.
• Frontier licences – aimed at new
areas, they offer a larger acreage and
are 10% of the cost of a traditional
licence for the first two years.
• Promote licences – for new entrants,
these allow an opportunity to assess
acreage for a two year period, at 10%
of the cost of a traditional licence. A
commitment to drill at least one well
or other significant activity is required
to retain the acreage.
• A total of 75 wells have been drilled on
fallow blocks or discoveries since 2002.
• 252 Promote licences have been awarded
so far – 65 in the latest round (the 24th).
• Six Frontier licences were awarded in the
latest round – the same number as in the
previous round.
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Oil & Gas UK | 2007 Economic Report
Objective Initiative Progress / Success
Promoting the Good
Stewardship of UKCS Assets
Stewardship – an annual review of the
performance of producing oil and gas
fields, carried out by DTI. Joint Venture
partners are engaged in discussions
about improving their Stewardship to an
acceptable standard. If a serious shortfall is
identified, the Stewardship process provides
a framework for improvement. If necessary,
DTI could require the Joint Venture to
undertake certain investment or change the
operator.
• Successful in raising awareness of
the benefits of critically analysing the
potential of individual assets.
Too soon to quantify outcome. A
number of cases with potential to
make improvements have been
identified.
•
•
Facilitating Access to
Infrastructure
Code of Practice on Access to
Infrastructure (ICoP) – aimed at improving
shared access to pipeline systems
and encouraging investment. Data
on infrastructure availability, service
standards, specifications and terms and
conditions of deals concluded under the
Code are available to aid transparency in
negotiations.
• Over 50 companies have signed the
ICoP (including all the infrastructure
owners).
38 Automatic Referral Notices (ARNs)
– a dispute resolution process – have
been submitted to DTI.
A review of its implementation shows
that the code is starting to influence
processes and behaviour.
•
•
•
Encouraging
Positive Commercial
Behaviour and Easier Asset
Transfers
Commercial Code of Practice – an agreed
framework for co-investors in assets
to minimise costs and time involved
in negotiations and promote positive
commercial behaviour. It helps facilitate the
transfer of assets.
• Over 95% of licensed companies have
signed.
Annual survey of transactions
and issues associated with them;
successful deals and their benefits are
highlighted.
•
•
Promoting a Strong Supply
Chain
Supply Chain Code of Practice – a set
of best practice guidelines aimed at
streamlining commercial processes, (e.g.
a system for selecting qualified suppliers –
FPAL, model invitations to tender – ITTs, use
of standard contracts – LOGIC), improving
behaviour during negotiations and
enhancing overall business performance.
It actively promotes 30-day payment for
goods and services.
• More than 90 companies have signed
the recently updated code.
2006 Share Fair a great success.
Suite of model ITTs is being developed.
Updating of the suite of standard
contracts is nearing completion.
Purchasers (operators and major
contractors) and suppliers have
been taking part in regular two-way
feedbacks of performance.
•
•
•
•
•
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Oil & Gas UK | 2007 Economic Report
C. Glossary of Terms and Abbreviations
bbl barrel (of oil) (1 barrel = 6.3 m3)
bcm billion cubic metres (1 metre3 = 35.3 cubic feet)
billion one thousand million
boe barrel of oil equivalent includes oil, gas and gas or other hydrocarbon liquids and equates all of these with oil,
so that a single measure can be made of two or more of them in combination
(1 boe = 164 m3 or 5.8 thousand cubic feet of gas)
bpd barrels per day
boepd barrel of oil equivalent per day
CCS carbon capture and storage
CNS central North Sea
CO2 carbon dioxide (one of the six “greenhouse gases” under the Kyoto protocol)
CT Corporation Tax
DTI Department of Trade and Industry
E&A exploration and appraisal (drilling)
EOR enhanced oil recovery
EU European Union
EU ETS European Union’s Emissions Trading Scheme
kboepd thousand barrels of oil equivalent per day
kbopd thousand barrels of oil per day
kWh kilo Watt hour (of electricity)
LNG liquified natural gas
m3/d cubic metres per day (of gas)
mtoe million tonnes of oil equivalent
MW Mega Watts (of electricity)
MS Member State (of the EU)
NNS northern North Sea
ONS Office of National Statistics
OSPAR Oslo and Paris Convention for the Protection of the Marine Environment of the North East Atlantic
OPITO training organisation for the offshore oil and gas industry
PILOT joint oil and gas industry - Government task force chaired by the Secretary of State
PRT Petroleum Revenue Tax
p/therm pence per therm
RoCE Return on Capital Employed
SCT Supplementary Charge to Corporation Tax
SNS southern North Sea (sometimes referred to as “southern gas basin”)
UKCS United Kingdom Continental Shelf
WoS west of Shetlands (sometimes referred to as “Atlantic margin”)
Oil & Gas UK Aberdeen
3rd FloorThe Exchange 262 Market StreetAberdeen AB11 5PJ
Tel: +44 (0)1224 577250Fax: +44 (0)1224 577251
Oil & Gas UK Brussels
6th Floor Rue Wiertz 50B-1050Brussels
Tel: +32 (0)2 286 1137Fax: +32 (0)2 230 9832
Oil & Gas UK London
2nd Floor 232-242 Vauxhall Bridge RoadLondon SW1V 1AU
Tel: +44 (0)20 7802 2400Fax: +44 (0)20 7802 2401
Email: info@oilandgasuk.co.ukWebsite: www.oilandgasuk.co.uk
Contact Oil & Gas UK
Report written by Sally Fraser, David Odling, Agustin Rivara and Mike Tholen, Oil & Gas UK.
Many thanks to our member companies who have supplied the photographs for the report.
This report has been produced with the full consideration to all relevant environmental issues. The papers used are Totally Chlorine Free (TCF), acid free, recyclable, biodegradable and manufactured from pulp taken from sustainable forests.
Designed and produced by Fiona Bridgeman, Oil & Gas UKPrinted by Chiltern Printers (Slough) LimitedCopyright © The United Kingdom Offshore Oil and Gas Industry Association Limited trading as Oil & Gas UK July 2007
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