Oil & Gas UK 2007 Economic Reportoilandgasuk.co.uk/wp-content/uploads/2015/05/EC010.pdf · C....

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


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


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



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



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


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


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

�


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


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


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


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


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

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r kW

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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


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

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eria

CIS

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Libya

15-40 Central Asia

85-115

16-35

12-25

5-10

15-2

0

Egypt

Algeria

Americas

Outlook for theUKCS in 2007

�


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


Forecast produc�on in 2010 based on dated survey

Trend of survey projec�ons

Forecast produc�on in 2010 based on trend


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


Probable new


Sanc�oned


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


Probable new


Sanc�oned



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


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



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


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



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.


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


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


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


-

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


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


Industry Perspectives

�


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


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



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.


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)


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.


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


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


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



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

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1.2

Tonn

es C

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n pe

r To

nne

oil e

quiv

alen

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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


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


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

�


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


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


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.


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.


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.

•

•

•

•

•

Page �1


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: [email protected]: 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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