Chapter 2 - Main Events of 2000 and Early 2001

2.1 The 19th Round of offshore petroleum licensing was announced on 10 November 2000. The announcement invited applications for blocks in the White Zone - the most recently designated part of the UK Continental Shelf between the Faroe Islands and Shetland - which has world-class petroleum potential. Applications closed on 27 February 2001. There was strong interest in a number of the blocks available for licence. The names of the successful applicants were announced on 8 May 2001. Licences covering 12 blocks are to be awarded to 13 companies. Successful exploration in the White Zone would give a significant boost to the long term future of the UKCS as a leading petroleum province.

2.2 The 19th Round is the first to be considered under regulations to apply the EU Habitats Directive to offshore oil and gas activities. Draft regulations were subject to public scrutiny following the launch of a consultation exercise in October 2000. The consultation exercise also invited comments on a strategic environmental assessment of the potential impact of oil and gas activities on the White Zone and the adjoining sea. The results of the consultation exercise were taken into account in decisions about which of the blocks offered in the 19th Round could be licensed and whether conditions need to be attached to any licences awarded to protect any specific environmental sensitivities.

The Saltire platform situated 201 kilometres North-east of Aberdeen.
Courtesy of Talisman Energy (UK) Limited

2.3 In January 2001 DTI also invited applications for Blocks 113/28 and 113/29 in the eastern Irish Sea which were formerly held under licence. These blocks, which contain two gas discoveries, were identified by PILOT’s Undeveloped Discoveries workgroup as having potential for development. The closing date for applications was 18 April 2001, and awards are due to be made later this year.

2.4 The 9th Round of Landward Petroleum licensing was announced in January 2000 inviting applications for Petroleum Exploration and Development Licences (PEDLs) in unlicensed areas of Great Britain above the Mean High Water Mark.

2.5 PEDLs enable the holder to explore for, appraise and develop the petroleum resources of Great Britain. Any exploration and development activity under a licence would need consent from the local planning authority and other approvals in the usual way. In addition, the Secretary of State’s consent is required for exploration drilling and for petroleum developments.

2.6 The initial results of the Round were announced in July 2000 with a second tranche of awards made in January 2001. In total, 44 licences were awarded to 30 companies for onshore oil and gas exploration in 136 blocks in England, Wales and Scotland.

2.7 The momentum for commercial extraction of coal bed methane as a valuable energy source has increased. Just under half the blocks awarded for licence had a coal bed methane or vent gas focus. Such developments are welcome as they provide a further boost for this fledgling industry and offer substantial environmental and public safety benefits if vent gas from abandoned coal mines can be exploited fully in the UK.

2.8 The UK’s onshore oil and gas industry has a strong future, as shown by the high level of interest in this Round. The areas covered by the awards range from Scotland to southern England and include acreage never previously subject to oil and gas exploration. It was also encouraging to see licences going to new applicants from both the UK and overseas.

2.9 All exploration for and exploitation of coal-related gases must be carried out in consultation with the Coal Authority and the operators of active mines in the vicinity. Further information on the possible exploitation of coal bed methane resources and associated technical and policy issues can be found in Government Energy Paper 67, published by The Stationery Office in April 1999. Copies are also available from the DTI website at: http://www.dti.gov.uk/ent/coal.

2.10 Under the Petroleum (Production) Act (Northern Ireland) 1964, landward petroleum licensing in Northern Ireland is the responsibility of the Department of Enterprise, Trade and Investment (Energy Branch, Netherleigh, Massey Avenue, Belfast BT4 2JP).

2.11 At the end of 2000 there were 8 landward petroleum licences covering an area of some 2,800 square kilometres. The Department operates an open licensing policy and is prepared to consider applications at any time. More information can be obtained from the above address or found in the publication "Minerals and Petroleum -Exploration and Development in Northern Ireland 1997-2000", available for Ł10.00 from The Stationery Office (020 7242 6393).

2.12 During 2000, development and production consent was given for 11 new field developments, and 12 other developments were approved by DTI (these are listed in Appendix 3). Anticipated capital expenditure linked to these projects is likely to amount to about Ł1.2 billion. The producing lives of many older fields have been extended through technological and commercial innovation and only two fields ceased production. The number of fields in production or under development continued to rise, reaching 264 by the end of the year.

2.13 During 2000, 14 pipeline works authorisations for the construction and use of 141 additional submarine pipelines were issued. The majority of these were infield flowlines associated with new field developments and incremental development of existing infrastructure. Interfield pipelines brought into use for the first time during 2000 have been added to the list of operating oil and gas pipelines in Appendix 14.

2.14 Blake, approved in January 2000, represents the opening up of the Outer Moray Firth for new discoveries and developments. As a subsea tie-back to the existing Bleo Holm FPSO, the Blake development lowers the unit operating costs and significantly extends the life of the existing Ross field. Production is expected to commence in the third quarter of 2001. Blake is a particularly good example of co-operation between licence groups leading to the best use of existing infrastructure to achieve an overall optimum development.

2.15 Jade, a gas condensate field, is the latest in a series of High Pressure, High Temperature field developments. Also approved in January 2000, Jade is located in quadrant 30 (Central North Sea), and will comprise a minimum facilities platform tied back to the Judy platform offering potential to open up further satellites in the area. Production is expected to start in late 2001 at daily rates of 15,000 barrels of oil and 200 million cubic feet of gas.

2.16 First oil was delivered to the Triton floating production, storage and offloading (FPSO) vessel in April 2000. The Ł540 million project, with some 78% UK content, incorporates the Bittern, Guillemot West and Guillemot North West fields. The vessel controls and processes oil and gas production from these three fields. Oil is exported by shuttle tankers and gas is exported via the Fulmar gas pipeline to St Fergus. Six partners were involved in the project, which demanded a new level of teamwork between investors, suppliers and fabricators in order to take these fields forward as a single development. The three fields have estimated reserves of some 140 million barrels of oil and 180 billion cubic feet of gas, and an expected field life of 13 years.

2.17 Though discovered in 1976, Skene has only now become viable as a result of technological advances in seismic acquisition, well design and subsea equipment, unlocking this major gas condensate field, with reserves of 95 million barrels of oil equivalent (BOE). Approved in July 2000, the development incorporates a heated flow-line bundle that will transport the hydrocarbons 15 kilometres back to the Beryl Alpha platform. This technology, previously used on the Britannia development, is required to prevent the formation of hydrates and wax crystallisation during periods of low production. It provides a link to the kind of technology that will be required to develop deep water gas fields along the Atlantic Margin.

2.18 The Brigantine development, also approved in July 2000, is located in the Southern North Sea (SNS). It requires an impressive level of technological innovation and demonstrates relatively low cost development techniques. Brigantine is a cluster of three fields developed from two platforms and the development will exploit reserves of some 270 billion cubic feet of gas. State-of-the-art reservoir analysis techniques and drilling extended reach horizontal wells will enable low risk recovery of maximum reserves. Brigantine employs the unique Trident platform design: a small, lightweight structure which more than halves the installation and operating costs of conventional platforms. Combined with extended reach horizontal wells, such innovative technology offers significant cost savings and plenty of future potential for development of satellite fields in the SNS.

2.19 The Shell UK-operated Shearwater field was officially inaugurated in September 2000 by Helen Liddell, the (then) Energy Minister. Facilities consist of a wellhead platform bridge-linked to the process, utilities and quarters platform (PUQ). The 11,600 tonne deck, fabricated at the AMEC yard in Wallsend, was towed offshore in March 2000 and lifted in place by the Heerema crane barge Thialf, setting a new record for the heaviest North Sea lift. Shearwater has been designed to handle gas production rates of around 410 million cubic feet per day and an export capacity of 90,000 barrels per day of condensate.

2.20 Shearwater, which has commenced production, has reserves of some 710 billion cubic feet of gas and 110 million barrels of condensate, to be developed over a field life of 12 years. Gas production is expected to plateau at 375 million cubic feet per day, meeting some 4% of UK requirements. Gas export is through a new 34" diameter, 473 kilometre long pipeline to Bacton. Condensate export is via a new 24" diameter, 38km long pipeline to the Marnock platform before onward transmission to Cruden Bay via the Forties Pipeline System.

2.21 Only the second major High Pressure High Temperature gas condensate field to be developed in the Central North Sea (CNS), much UK expertise was devoted to Shearwater. Scope for other developments in the CNS has been provided by the pipeline to Bacton, which also provides infrastructure opportunities for gas export from the CNS to Europe. Total expenditure on the Shearwater project is estimated at Ł876 million, some 70% of which has been spent in the UK. Above all, Shearwater provides an excellent example of what can be achieved when UK suppliers and operators work closely together.

2.22 The Leadon oil field gained DTI approval in December and was the largest project to be given the go ahead in 2000. Discovered in 1979 but not developed by its previous operators, Leadon will be brought onstream using a floating production and storage system being built at the Swan Hunter yard on Tyneside. The Kerr-McGee operated field, which brings jobs onshore and offshore, was originally thought uneconomic until an appraisal well drilled in 1999 proved a northern extension to be oil bearing. Production will commence in early 2002 and is expected to peak at over 40,000 barrels per day.

2.23 Also in December 2000, consent was given to BP for the Magnus pipeline, the first from the deep Foinaven and Schiehallion fields West of Shetland. This unique project, costing some Ł320 million, will take surplus gas via the Sullom Voe oil terminal on Shetland to the North Sea’s most northerly oil platform on the Magnus oilfield, some 340 miles north east of Aberdeen. There the gas will be injected into the oil reservoir 8,900 feet under the seabed to flush out an extra 50 million barrels of oil. The gas -equivalent to another 50 million barrels of oil - will be recovered and landed via another pipe network for use onshore, providing first access to West of Shetland gas which currently has to be re-injected locally. This unique project demanded a high level of collaboration between more than 20 partners, once again proving the success of innovative commercial arrangements for exploiting the UKCS reserves.

2.24 The successful completion of installation and processing work allowed first oil to flow from Area B of Texaco’s Captain oil field on 27 December. The Ł350 million Captain Expansion employs horizontal drilling techniques and, for the first time in an oil field development, gas handling downhole hydraulic submersible pumps specially developed for the project. Completed within a 25-month schedule, the expansion will allow for production from the field (60,000 barrels a day) to be increased to 85,000barrels a day by autumn 2001. Field life is now projected beyond 2015.

2.25 The Elgin gas condensate field commenced production in March 2001. The Elgin/Franklin development is a significant achievement, with total expenditure amounting to some Ł1.65 billion. Located in the Central North Sea, Elgin establishes a new UK record depth (below 17,500 feet) for hydrocarbon production and is now the hottest (around 190°C) producing field in the UKCS.

2.26 Elgin has reserves of 850 billion cubic feet of gas and 230 million barrels of condensate to be developed over a field life of 22 years. Gas production is expected to peak at over 350 million cubic feet per day. Production facilities comprise a permanently manned process, utilities and quarters platform, which is bridge-linked to a separate wellhead platform.

2.27 The export pipelines are shared with the Shearwater field. Gas export is through the new 34" diameter, 473 km long SEAL pipeline to Bacton and condensate export is via a new 24" diameter, 38km long pipeline to the Marnock platform before onward transmission to Cruden Bay in NE Scotland, via the Forties Pipeline System.

2.28 Elgin/Franklin is the largest development on the UKCS in recent years and at its peak the project employed more than 5,000 people, creating 160,000 man months of work in the UK. Including onshore and offshore workers, the project will support some 260 new jobs.

Elgin/Franklin Project -Sailaway of the Production/ Utilities/Quarters platform
Courtesy of TotalFinaElf

Topside facilities at the Captain Field
Courtesy of Texaco
PHOTO: CHRIS SANDERS

2.29 UKOOA’s Economic Report for 2000, published in February 2001, suggested that operators’ capital expenditure in 2001 could be close to Ł4 billion. With oil prices still remaining high during 2000, and the positive collaboration and ideas coming out of PILOT, oil companies provided clear signals about their future commitment to the UKCS.

2.30 Record levels of production were maintained in 2000, with 126 million tonnes of oil and natural gas liquids (NGLs), and 115 billion cubic metres of gas being produced. Although oil production was 8% lower than 1999, increased gas production helped to ensure that combined production (in BOE) in 2000 was only 1% lower than the previous year. The lower oil production largely related to maintenance shut-downs on offshore platforms. (When oilprices fell to around $10 per barrel in late 1998/early 1999, oil companies cut back on all but essential maintenance work, subject to not compromising safety, and 2000 saw companies catching up on previously postponed work.)

2.31 Additional gas supplies started coming ashore in 2000 from six new oil/condensate fields. This contributed to the increased gas production during 2000.

2.32 Production of NGLs in 2000 was 8.4 million tonnes, including 2.0 million tonnes of condensates.

Field Name	Field Type	Month Field Came Onstream
	OIL/CONDENSATE
Bittern	Offshore Oil	April 2000
Cook	Offshore Oil	April 2000
Guillemot West	Offshore Oil	April 2000
Guillemot North West	Offshore Oil	May 2000
Shearwater	Offshore Condensate	September 2000
Keith	Offshore Oil	November 2000
	GAS
Europa	Offshore Gas	January 2000
Vixen	Offshore Gas	August 2000
Skiff	Offshore Gas	October 2000

2.34 Production ceased from two offshore oil fields, Bladon and Blenheim, in April 2000.

2.35 Appendix 11 shows sources of UKCS oil and gas received at UK terminals during 2000. Additional information on oil and gas disposal and exports can be found in the UK Digest of Energy Statistics, available on the DTI website at http://www.dti.gov.uk

2.36 26 exploration wells drilled offshore in 2000, showing a distinct improvement on 1999 when only 16 were drilled. However, the industry still has work to do to realise the PILOT "target" rate of 50 a year. The level of appraisal drilling was higher than last year (when 20 wells were drilled), with 33 wells drilled in 2000, including 11 sidetracks. The Northern North Sea has shown the largest recovery.

2.37 Six significant discoveries were announced last year, signifying a success rate close to 25%.

2.38 Six new exploration wells were drilled (three in each area), an increase on 1999. Of the three drilled West of Shetland, two were 16th Round commitments and the other located on a 17th Round Tranche. One significant discovery was announced. Two appraisal wells were drilled, relating to the Schiehallion field area.

2.39 Six exploration wells were started compared with only one in 1999. Three significant discoveries have been announced, giving an excellent success rate of 50%. Appraisal drilling is back up to 1998 levels, with 16 wells spudded. Only four appraisal wells were drilled in 1999.

2.40 Exploration activity in the Moray Firth increased to seven wells (including two sidetracks) compared with five drilled in 1999. One significant discovery was announced and one well was drilled on a fallow block. Four appraisal wells were drilled, down from six the previous year; however, one confirmed a significant discovery drilled by a finder well the previous year.

Valve inspection being carried out on the Piper 'B' platform.
Courtesy of Talisman Energy (UK) Limited

2.41In the Central North Sea, drilling activity was slightly lower than last year. Two operators drilled four exploration wells. Two of these wells were on 18th Round acreage and one was on a 1st Round award, but no discoveries were announced. Seven appraisal wells were drilled (including one well sidetracked to a deeper horizon), and one of the successful appraisal wells is now tied back and producing.

2.42 Three exploration wells were started during 2000, with two still on location at the end of the year.

2.43 Three successful appraisal wells were drilled. One of the wells discovered the North Davy field, which is being fast tracked for development.

2.45 Eight exploration and six appraisal wells were drilled onshore in 2000. Of these, all except one were targeted at coalbed methane or mines gas, illustrating the continued interest in these gas resources. No discoveries were announced although some well tests are planned.

2.46 Offshore development drilling is still above 200 wells a year, with 216 wells started including 80 sidetracks. The total comprises both new field drilling and infill wells, some on fields that have been on production for many years. A regional breakdown appears at Appendix 4.

2.47 Eleven development wells were drilled, four of which were sidetracks. Ten of the wells were on conventional oil and gas fields; the eleventh was associated with a mines gas development.

2.48 The innovative use of new technology and flexible commercial arrangements mean that many fields which were expected to have reached the end of their lives are still in production. However, at some stage all oil and gas fields become uneconomic. DTI is responsible for ensuring that the decommissioning of the facilities on UK fields is managed in an orderly fashion.

2.49DTI has published Guidance Notes for Industry on the Decommissioning of Offshore Oil and Gas Installations and Pipelines under the Petroleum Act 1998. The Notes, which are consistent with the UK’s international obligations, provide a clear and comprehensive guide to the approval process and were published on 21 August 2000. They are available on the Oil and Gas Directorate’s website at: http://www.og.dti.gov.uk/decom/dcom_hom.htm.

2.50 In December 2000 DTI approved the decommissioning programme submitted by Phillips Petroleum Company and their partners for the Maureen and Moira field facilities. Decommissioning will involve the refloat and removal of the Maureen Alpha platform and associated equipment, including the oil loading column and drilling template, and the removal of the Moira subsea facilities. The oil export line between the platform and the loading column will be left in place and will be subject to a post-decommissioning monitoring regime.

2.51Refloat is scheduled for June 2001; the programme provides for the installation to be re-used or, if a re-use opportunity is not forthcoming, to be recycled.

2.52 During 2000, decommissioning programmes were also approved for the Blenheim and Bladon facilities and for the first decommissioning phase of the Durward and Dauntless fields. Under these programmes all of the facilities have been removed from the seabed and returned to shore. The Decommissioning Programme for the Camelot CB installation was approved early this year. The platform will be sold for re-use should a suitable opportunity arise; if not, the platform will be returned to shore for recycling.

2.53 DTI is a member of the UKOOA Joint Industry Project (JIP) to study the issues associated with the accumulation of drill cuttings beneath some offshore installations. Phase 2 of the JIP work to identify the best environmental practice and the best available techniques for dealing with drill cutting deposits continued throughout 2000. Onshore trials of potential cuttings recovery systems were undertaken in August and offshore trials are scheduled for Summer 2001. The Phase 2 studies are expected to be completed by early 2002 and final conclusions presented to the OSPAR Oil Industry Committee (OIC) in February 2002. A progress paper was submitted by the DTI to OIC in February 2001. Further information on the work of the JIP is available from the UKOOA website at: http://www.oilandgas.org.uk/issues/drillcuttings.

2.54 The Gas (Third Party Access and Accounts) Regulations 2000, which gave effect to this Directive, came into force on 10 August 2000. The Regulations amend those parts of the Petroleum Act 1998, the Pipe-lines Act 1962 and the Gas Act 1995 which make provision for access to certain oil and gas infrastructure, onshore and offshore. The main changes in respect to access to upstream pipelines and interconnectors are that the legislation now makes clear that applications for access must be made in the first instance to the relevant pipeline owner. The Secretary of State’s role as dispute settlement authority has been clarified, as have the factors he may take into account when considering disputes about pipeline access. The Regulations have introduced a new requirement on owners of onshore gas processing facilities/terminals, and onshore pipelines connecting such facilities to the National Transmission System or directly to larger users, to publish their main commercial conditions for access.

2.55 On 15 November 2000 the Secretary of State for Trade and Industry concluded that the programme of reforms in the electricity market was substantially complete and lifted the stricter consents policy applying to new gas-fired power stations, with immediate effect. Lifting the policy meant the prevailing presumption against new gas-fired power generation would no longer apply. In future the policy requirement on developers would be that in considering new power station proposals they explore the opportunities to use combined heat and power (CHP) and in March 2001 the DTI published guidance to developers on what that meant. A number of significant gas-fired power station proposals were given the green light with the lifting of the stricter consents policy and DTI continues to see a strong interest in gas-fired power stations.

2.56 Sharp rises in the spot and forward price of gas have occurred since Spring 2000, affecting in particular industrial and commercial customers who are contractually exposed to the spot price. The major cause of the price rise has been arbitrage across the UK-Belgium Interconnector with high oil related gas prices in Europe. This situation has arisen because of the lack of liberalisation and competition in Europe and the consequent lack of gas-to-gas competition. When the Interconnector was commissioned in 1998 it did not have a significant upward pressure on prices because at the time the oil related gas prices in Europe were low. However, as oil prices increased so did Continental gas prices. Trade across the Interconnector has caused the UK price to rise as well.

2.57 The Government is concerned about the price rises and has a three point strategy to tackle the problem, involving:

2.58 In January 2001 the Secretary of State for Trade and Industry wrote to Commissioner Monti to request a competition inquiry on the operation of the Interconnector which, on 1 February 2001, the Commission agreed to undertake.

2.59 Since 1976, DTI has conducted a quarterly inquiry covering all oil and gas exploration and production licensees. In this inquiry, licensees provide figures on sales and development, exploration and operating expenditures. Where possible, the development and operating expenditure figures are split between oil and dry gas fields. Figures for the period 1990 to 2000 are presented in Appendix 7, together with the criteria used for splitting oil and gas costs.

2.60 Sales are, of course, affected by both production and prices. Production remained at record levels in 2000, as the rise in gas production to a new record level more than compensated for the fall in oil production. Annual production levels of oil and gas since 1970 are illustrated in Chart 2.4.

2.61 The annual average price received for oil rose rapidly between 1978 and 1984 but then fell sharply, decreasing further to a low in 1988. Since then, prices have moved in a range between Ł77 and Ł97 a tonne until hitting a fifty-year low in real terms in December 1998. Oil prices improved during 1999 from just over Ł50/tonne in the first quarter to some Ł108/tonne in the last quarter. The increases continued throughout 2000 so that the average oil price received by producers from sales of UKCS oil was some Ł137/tonne.

2.62 The annual average price received for gas by UKCS producers rose in most years until 1991, after which it fell back slightly for the next two years. Prices then improved until 1994 and remained between 16 to 17 pence a therm until falling to under 14p/therm in 1999. Prices rose to just over 16p/therm in 2000. Annual prices for sales of oil and gas from the UKCS are shown in Chart 2.5.

2.63 The total income of operators and licensees rose from Ł17.5 billion in 1999 to just over Ł25 billion in 2000. The rise was aided by increased prices so that sales of oil and NGLs rose from Ł11.0 billion to Ł17.2 billion despite a fall in production. With increased production and higher prices, gas sales rose from Ł5.0 billion to Ł6.6 billion. Other income of operators and production licensees, which had fallen back in 1999 after rising since 1990, recovered to over Ł1.5 billion in 2000.

2.64 Unit operating costs increased in 2000 from the recent low seen in 1999 as operating costs for oil and gas extraction rose to just over Ł4.3 billion without a corresponding increase in production. This is probably due to the return of non-essential maintenance work, which had been postponed in 1999 when companies’ cash-flow was suffering under low prices. Unit operating costs (given as operating costs per tonne in real terms) are shown in Chart 2.6. The fairly continuous rise from 1976 to 1991 is not unexpected as unit costs of fields rise when production begins to fall, and new fields often pay to use existing infrastructure so that operating costs are higher but capital costs are reduced. The peak around 1991 reflects the heavy expenditure on safety improvements following the Cullen Inquiry into the Piper Alpha disaster, and the fall thereafter demonstrates the effectiveness of CRINE and other industry cost reduction efforts.

2.65 Expenditure on exploration and appraisal (E&A) is estimated at under Ł0.4 billion in 2000, a small decrease on 1999, but considerably less than the Ł0.75 billion seen in 1998 and Ł1.2 billion in 1997. The number of well starts rose encouragingly from 36 to 59 (from 31 to 45 excluding sidetracks), but still lower than the 80 wells in 1998.

2.66 Production investment (i.e. other than on E&A) by operators and licensees declined with the fall in oil prices at the end of 1985 until beginning to increase again in 1987 to reach around Ł5.0 billion between 1991 and 1993. After this development of an unusually high number of large projects, it fell to some Ł3.7 billion in 1994, before recovering again to some Ł4.4 billion between 1995 and 1997, and to Ł5.0 billion in 1998. Production investment fell back in 1999 to some Ł3.1 billion, remaining close to this level in 2000 at Ł2.7 billion. Investment by operators and licensees on the UKCS, together with the division between oil fields and gas fields, is shown in real terms for each year since 1976 in Chart 2.7.

2.67 Investment on construction attributable to the development of gas fields, pipelines and terminals fell a little to some Ł1.0 billion from the Ł1.2 billion seen in 1999. Investment on the development of oil fields, pipelines and associated equipment also fell slightly to Ł1.8 billion from Ł1.9 billion in 1999. Expenditure on platform structures and equipment rose slightly for both oil and gas fields. Expenditure on development wells fell as the number of wells dropped a little to 216. Moreover, the share of expenditure on development wells fell for both oil and gas fields, having previously risen each year for some years.

2.68 The total project investment committed by operators to projects approved in 2000 was Ł1.2 billion. This figure excludes the capital cost of hired equipment. The corresponding figure for investment in 1999 was Ł0.2 billion.

2.69 To take account of both capital and operating costs, estimates have been made of the field life cost per barrel for all oil and condensate fields which have been approved - see Table 2.1. These overall estimates, which are rounded to the nearest Ł0.5/barrel, are based on the estimated production and costs of the fields together with their equity share of pipelines and terminals, before the payment of royalty and taxes. They include the costs of development and operation over the expected life of the fields, but exclude abortive exploration costs not attributable to individual fields. A real return on capital of 10 per cent is assumed. The figures can therefore be interpreted as the constant real oil price which would yield a pre-tax real rate of return of 10 per cent.

	Oil fields*	Gas fields
	Ł/barrel	p/therm
Fields starting production before 1980	11	9
Fields starting production 1980-1985	16	23
Fields starting production 1986-1990	14	21
Fields starting production 1991-1995	9	14
Fields starting production 1996-2000	9	14
All fields in production	11	13.5

* Including condensate fields - and oil equivalent of associated gas. Excluding tax and royalties, and costs of abortive exploration.

2.70 The industry responded to the fall in oil prices at the end of 1985 and brought the cost of oil fields down so that those starting production in the period 1986 to 1990 require an average of Ł14 a barrel to obtain a return of 10 per cent. Costs for fields starting since 1991 have been reduced substantially so that they need an average of only Ł9 a barrel over their production lives. For all oil and condensate fields now in production, an average of Ł11 a barrel is required.

2.71 The equivalent calculations for gas fields also show a large rise in costs for fields starting between 1980 and 1985, the success of efforts to reduce costs since then and the success of continued cost reduction. The equivalent average price required for all gas fields in production is 13.5p/therm.

2.72 The direct impact of oil and gas production has improved the UK balance of payments considerably. The net contribution of trade in oil was Ł0.3 billion in 1980, rising steadily to Ł8.0 billion by 1985. It has not reached that level since then due to the fall in prices, but has always remained positive. The contribution is estimated to have risen from around Ł4.0 billion in 1999 to some Ł6.0 billion in 2000.

2.73 The oil and gas industry sector in the National Accounts also includes contractors and agents providing services which are unique to the industry. Contractors include companies employed in drilling or operating platforms for the licensed operators, but not companies whose principal work is classified to other industrial sectors such as seismic work or construction.

2.74 Since the start of major development in 1965, the industry sector has generated gross operating surpluses totalling some Ł272 billion. Some Ł108 billion, including Ł24 billion on E&A, has been re-invested in the UK oil industry. Revalued to 2000 prices, this represents an investment of some Ł194 billion, including Ł42 billion on E&A.

2.75 The oil and gas sector’s share of total Gross Value Added (GVA is the measure now used by National Accounts to assess the contribution of industries, rather than Gross Domestic Product) rose between 1992 and 1996 with increased production but fell to 1.7% by 1998. Oil and gas GVA rose with the rise in prices to 1.9% in 1999, and to an estimated 2.7% in 2000. Capital investment, including E&A, formed around 12 per cent of total UK industrial investment and some 2 per cent of gross fixed capital investment.

2.76 The Government’s objective is to maximise the benefits to the nation from the exploitation of its hydrocarbon resources. Government revenues from oil and gas produced on the UK Continental Shelf are made up of Royalty, Petroleum Revenue Tax (PRT) and Corporation Tax. The fiscal regime is designed to extract economic rent and secure a fair share of profits for the nation, while offering stable, attractive and economically sound investment conditions to the oil industry. It is described more fully in Chapter 3.

2.77 Receipts to the Government from taxes and royalties on oil and gas production (including licence fees) reached a peak of Ł12.2 billion in 1984/85 (equivalent to Ł22.9 billion in 2000/01 prices). Receipts subsequently declined with the fall in oil prices to a low of Ł1.0 billion in 1991/92 (equivalent to Ł1.3 billion in 2000/01 prices) and are estimated to have totalled some Ł2.6 billion in 2000/01. Since 1964/65, the Government has received a total of Ł95.7 billion in money of the day or Ł165.8 billion in 2000/01 prices. Exchequer receipts since 1964/65 are given in Appendix 8. Receipts since 1976/77 are illustrated, together with oil prices and total oil and gas production, in Chart 2.8; receipts and oil prices are both shown in constant 2000/01 prices.

Chart 2.8 North Sea Tax Revenues and Oil Prices (in constant 2000/01 prices) and Oil Equivalent Production

2.78 The Office for National Statistics (ONS) gives figures for employment classified to the oil and gas extraction sector, which includes not only those engaged in extraction offshore and onshore but also certain classes of services peculiar to the industry. Many oil related jobs such as construction workers are classified to other industries and are not included in ONS figures. ONS shows employment at some 27,000 in 1978, peaking near 37,000 in 1990 and 1991, before falling sharply to around 25,500 in 1994 and 1995. Employment then recovered to near 29,000 between 1996 and 1998, before falling back to some 26,400 in 2000 (n.b. it should be noted, in case there are seasonal effects, that the February 2000 survey figures are given). These figures are illustrated in Chart 2.9.

Chart 2.9 Employment in the oil and gas sector, and employment offshore, 1978 to 2000

2.79 Figures for offshore employment have been collected since 1967. The first annual surveys collected only numbers employed offshore on rigs and platforms and showed employment at just over 1,000 workers in 1967, rising steadily through the 1970s to 12,500 in 1978, before falling back in 1979. From 1980 onwards the survey included workers on pipe-laying vessels, crane barges, supply and standby vessels. The new survey showed offshore employment at 22,000 workers in 1980, rising to 31,300 in 1984, before slumping to near 22,000 in 1986. Offshore employment rose again to peak at 36,500 in 1990, after which there was a general downward trend with attempts to reduce costs. However, the 1993 and 1995 figures were both unexpectedly high due to the number of large fields under development on the day of the survey. These offshore employment figures are also shown in Chart 2.9.

2.80 These offshore surveys are co-ordinated by Inland Revenue, with the support of industry provided through UKOOA, as the main purpose was to assist with tax compliance in the offshore oil and gas industry. Aggregated results are distributed to government and industry bodies and are used, for example, by the Health and Safety Executive and UKOOA to calculate accident and safety statistics. Changes were introduced in the September 1996 survey following an Inland Revenue initiative, which also assisted the industry aim to improve the accuracy of accident statistics. Since 1999, the survey has been conducted twice a year, in February and August. The estimate for August 1999 was some 19,000 and for February 2000 was 21,200 of whom some 98% were EU nationals.

2.81 The latest UKOOA estimate is that 270,000 jobs were supported by the offshore oil and gas industry in 1999. Around 44% of these jobs were in Scotland, but oil related jobs exist in almost every part of the country. Previous studies commissioned by UKOOA estimated that the UKCS directly and indirectly supported a total of some 210,000 jobs in 1997. This total included some 34,600 jobs directly associated with offshore activities, and just over 175,000 additional jobs with suppliers and prime contractors and their sub-contractors and others further down the supply chain. A further 150,000 jobs depended on the spending of employment income by those in the 210,000 directly and indirectly supported jobs to give nearly 360,000 jobs affected by UKCS activity.

2.82 The UKOOA figure for Scotland is close to that given by Scottish Enterprise, who believe that the oil and gas sector accounts for approximately 116,000 oil related jobs in Scotland, amounting to 6% of the Scottish workforce.

	encouraging Member States to increase liberalisation and competition in Europe;
	looking at ways of improving the functioning of the UK market; and
	acting against any evidence of anti-competitive behaviour in the market.