3.1 The Government is committed to ensuring that offshore activity takes account of its environmental impact. During 2000, DTI’s Oil and Gas Directorate (OG) was restructured to allow a greater emphasis to be placed on the offshore environment. The Oil and Gas Environment and Decommissioning Branch was created, made up of:
|
The Offshore Environmental Operations Unit, which carries out inspections and ensures implementation of, and compliance with, environmental legislation; |
|
The Offshore Environmental Policy and Policy Development Units, responsible for the development of environmental legislation and ensuring that UK interests are fully represented in EU, international and national fora; |
|
The Offshore Decommissioning Unit, responsible for ensuring that decommissioning activity is carried out in a manner which meets legislative requirements, uses best available engineering and environmental practice, and avoids unnecessary taxpayer exposure. |
3.2 The Branch is also responsible for dealing with prevention and detection, and emergency response in the event of an offshore pollution incident. Most staff in the Branch are based in Aberdeen.
3.3 The offshore environmental regime has, over thirty years, developed in response to changing impacts on the environment and changes in society’s perception of these. It is made up of primary and secondary legislation, conditions in consents granted under the petroleum licensing regime and international conventions. The regime continues to develop.
Clipper installation, North Sea
Courtesy of Shell UK
The Offshore Chemicals (Pollution Prevention and Control) Regulations 2001
3.4 These will implement on the UKCS the OSPAR Decision 2000/2 on a Harmonised Mandatory Control System (HMCS) for the use and reduction of the discharge of offshore chemicals. The regulations are expected to come into force in July 2001 and will require the use and discharge of offshore chemicals to be subject to a permit issued by the Secretary of State for Trade and Industry. The purpose of the Decision is to seek the use of less hazardous chemicals wherever possible.
3.5 This requires all Member States to protect specified rare plant and animal species and certain endangered local environments or "habitats". Under the Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001 the Directive is applied to oil and gas activities on the UKCS beyond the 12-mile territorial waters limit. The effect is that any oil and gas activity likely to have a significant impact on such a habitat will be subject to assessment by the competent authority, which in the UK is the Oil and Gas Directorate. Similar provisions already exist for activity within the 12-mile limit under the Conservation (Natural Habitats and Conservation) Regulations 1994, as amended. Responsibility for identifying the habitats lies with the Department of the Environment, Transport and the Regions (DETR) and the Joint Nature Conservation Committee (JNCC).
3.6 Following Lord Donaldson’s review of the Sea Empress incident in 1995 (the Command and Control Report of Lord Donaldson’s Review of Salvage and Intervention and their Command and Control), new regulations are due to come into force to implement his recommendations offshore. These will give the Secretary of State powers to appoint a single representative to act on his behalf, with the appropriate powers and responsibilities to monitor incidents and intervene to protect the marine environment from risk of significant or actual pollution.
3.7 The Government has discretion to require an EIA for exploration, appraisal and development wells. During 2000, 21 environmental statements covering 2 exploration wells in the Atlantic Frontier and 19 projects (wells and developments) in the North Sea, Irish Sea and English Channel were received. In addition to this, DTI received 258 requests for determination that environmental impact assessments were not necessary. OG rejected several of these on the grounds that the environmental impacts may be different to those suggested by the operator. The operator was then required to carry out a full environmental impact assessment of the area.
3.8 In November 2000, DTI successfully prosecuted an operator for a breach of section 3 of the Prevention of Oil Pollution Act 1971. The operator entered a guilty plea to the Crown Court and was fined £40,000 plus costs. DTI are currently investigating an oil leak from a pipeline in the Northern North Sea. A report into the investigation has been submitted to the Procurator Fiscal in Aberdeen. During 2000 DTI has been in discussion with the Procurator Fiscal’s Office in Scotland to establish a more cohesive structure for oil spill investigations offshore.
3.9 Chart 3.1 gives a breakdown of the quantities of oil spilled during the period 1991 to 2000 while Table 3.1 shows the reported figures. The total amount of oil spilled during 2000 was 78 tonnes which continues the downward trend of recent years. The number of reports made to the DTI increased from 372 in 1999 to 423 in 2000. It is clearly evident that the trend for reporting even the smallest of spills continues, with 405 reports for spills of less than 1 tonne; these represent 96% of reports.
Chart 3.1 Oil Spills
Reported to the Department 1991-2000
Table 3.1 Oil Spills Reported to the Department 1991 - 2000
|
1991 |
1992 |
1993 |
1994 |
1995 |
1996 |
1997 |
1998 |
1999 |
2000 |
|
|
Total Amount Spilled (tonnes) |
192 |
225(1) |
224 |
174 |
84(2) |
127 |
866(4) |
137(5) |
120(7) |
78(8) |
|
Of which: |
||||||||||
|
Oil from oil-based mud spills |
116 |
49 |
145 |
74 |
29 |
28 |
38 |
35 |
3 |
0.5 |
|
Other oil spills |
76 |
176 |
79 |
100 |
55 |
99 |
828 |
102 |
117 |
70.5 |
|
Third Party Reports |
7(9) | |||||||||
|
Number of Installations Reporting Spills |
39 |
43 |
43 |
50 |
52 |
77 |
96 |
101 |
112 | 117 |
|
Total Number of Reports |
234 |
194 |
183 |
147 |
145 |
300(3) |
349(3) |
392(3) |
372(3) |
423(3) |
|
Total Stabilised Crude Oil Produced from Offshore Fields (million tonnes) |
83.1 |
89.1 |
90.2 |
114.4 |
116.7 |
116.7 |
115.3 |
118.9(6) | 124.0 | 114.6 |
3.10 In 2000, 300 hours were flown on 55 ‘dedicated’ oil rig patrols i.e. those funded solely by the DTI. In total, 2,219 surveys of installations were undertaken. The total amount of oil observed from unreported spills was just over 1 tonne from 32 separate detections.
3.11 The Department uses a computer link to the aerial surveillance aircraft which transmits photographic images of pollution incidents and enables the Department to investigate oil spill incidents as they happen. The Department is upgrading the computer link to include the transmission of video imagery.
3.12 The Scottish Fisheries Protection Agency, MAFF and the Maritime and Coastguard Agency also undertake routine overflights of the UK waters. The DTI works closely with these agencies to ensure that any oil spill emanating from an offshore installation is reported, so the effective level of surveillance is significantly greater than the 300 hours currently funded. In particular, the Maritime and Coastguard Agency routinely survey the gas platforms in the Southern North Sea.
3.13 The programme of environmental inspections in 2000 raised no significant concerns about operators’ performances. Three new environmental inspectors joined OG in 2000 and it is anticipated that more inspectors will be appointed during 2001.
3.14 The discharge of oil-contaminated produced water from offshore installations is permitted by an exemption granted under the Prevention of Oil Pollution Act 1971, but the oil content must not exceed 40 parts per million. It has proved difficult for a few installations, in particular those operating in mature fields, to meet this target. In 2000, of 68 installations discharging produced water, 3 exceeded this target when averaged over the whole year. These installations took steps to identify specific problems and made improvements to systems to ensure that by the end of 2000 there were significant improvements in performance. The average content of oil in produced water for the year, for the UKCS as a whole, was 21.5 parts per million, the same as in 1999 which was the lowest value yet recorded in the UKCS.
3.15 Following a period of phase-out, Government and industry succeeded in ensuring that the discharge of unacceptable synthetic drilling fluids was reduced to zero by 31 December 2000.
3.16 Under the terms of petroleum production licences, gas may be flared only with the consent of the Secretary of State. During 2000 an average of 4.76 million cubic metres of gas a day was flared at offshore installations. This represents a fall of just over 17% over 1999. Flaring at onshore fields was minimal during 2000.
The Franklin wellhead platform and the drilling rig
Magellan alongside.
Courtesy of TotalFinaElf
Table 3.2 Oil Discharged with Produced Water 1991 - 2000
|
1991 |
1992 |
1993 |
1994 |
1995 |
1996 |
1997 |
1998 |
1999 |
2000 |
|
|
Total Oil Discharged (tonnes) |
5490 |
4850 |
4232 |
4418 |
5855 |
5706 |
5767 |
5692 |
5641 |
5395 |
|
Total Water Discharged (million tonnes) |
153 |
135 |
148 |
147 |
192 |
210 |
234 |
253 |
261 |
244 |
|
Number of Installations Permitted to Discharge Oil |
39 |
43 |
46 |
52 |
55 |
60 | 64 | 64 | 73 | 68 |
|
Average Oil in Water Content (mg/kg) |
35 |
36 |
28 |
30 |
30 |
27 |
25 |
22 |
21.5 |
21.5 |
Chart 3.2
Average Oil in Water Content
3.17 DTI is responsible for the implementation and development of Government policy on decommissioning offshore oil and gas installations and pipelines.
3.18 The primary legislation which regulates the disposal of redundant installations and pipelines is the Petroleum Act 1998, which enables the Department to place a decommissioning obligation, in the form of a notice, on the co-venturers of every offshore installation, and the owners of every offshore pipeline, on the UKCS. The companies served with a notice are jointly and severally liable to submit a decommissioning programme for approval and to ensure that the provisions of the programme are implemented.
3.19 The Government’s policy on the decommissioning of offshore installations and pipelines is set out in the DTI’s Guidance Notes for Industry published in August 2000 (see also Chapter 2).
3.20 These confirm the Government’s approach to decommissioning and to managing the decommissioning of offshore installations in an environmentally responsible manner. They reflect the terms of OSPAR Decision 98/3, adopted by OSPAR Ministers in July 1998, and the presumption that oil and gas installations will be completely removed for re-use, recycling or final disposal on land. At the same time, in line with the OSPAR Decision, the Guidance Notes recognise that there may be difficulty in removing concrete installations and the ‘footings’ of large steel jackets and provide for the possibility of derogation for these categories of installation.
3.21The Government is keen to encourage the re-use of facilities wherever this is practicable and will expect Operators to demonstrate that they have investigated re-use opportunities fully at the decommissioning stage. Changes in the tax allowances applicable to decommissioning costs, announced by Inland Revenue in August 2000, will also make re-use more attractive.
3.22 The Government is also keen to encourage a free trade in mature offshore oil and gas assets as a means of extending field life and maximising economic recovery. At the same time it has a duty to ensure that the taxpayer is not exposed to an unacceptable risk of default in meeting the costs associated with decommissioning. DTI therefore ensures that adequate security for decommissioning costs is available and in a small number of cases the DTI has required that Financial Security Agreements (FSAs) are established. Details of this policy and the circumstances in which the Government may ask the owners of offshore installations and pipelines to enter into an FSA can be found in Annex F to the Guidance Notes.
3.23 Any activity to explore for or exploit petroleum in Great Britain, the territorial waters and on the UK Continental Shelf can be carried out only under a petroleum licence. Regulations re-enacted under the Petroleum Act 1998 set out how applications for licences are to be made, the terms and conditions that will be applied to any licences granted and the criteria to be taken into account when doing so. There are separate regulations covering the Seaward and Landward areas.
3.24 The extension of the Habitats and Birds Directives to the UK Continental Shelf means that decisions about granting of licences also need to take account of the likely impact of doing so on proposed and designated Special Areas of Conservation and Special Protection Areas.
3.25 The licensing regime is explained in more detail on the Oil and Gas Directorate’s web-site (http://www.og.dti.gov.uk) and in a DTI brochure "The Right Framework" (available free of charge from the Department - Tel: 020 7215 5173).
3.26 The special UKCS tax regime is designed to secure an appropriate share of profits for the nation while offering stable, attractive and economically sound investment conditions to the oil industry. It is kept under review and many adjustments have been made to it to reflect changes taking place in the UKCS.
3.27 The main elements of the current UKCS fiscal regime are:
|
Royalty, which is paid, as a condition of each oil production licence, at 12.5 per cent of the landed value of petroleum "won and saved", less an allowance for the cost of bringing the petroleum ashore and treating it. Royalty is not payable for any field approved after 31 March 1982. |
|
Petroleum Revenue Tax (PRT), which was introduced by the Oil Taxation Act 1975. PRT is a tax on profits related to separate geological and technically determined fields, charged on the difference between income and expenditure with allowances designed to ensure it bites only on the larger, more profitable fields. A significant reform of PRT was introduced in the 1993 Finance Act to encourage further investment by allowing the oil companies to keep more of their income. The rate of PRT charged on existing fields was reduced from 75 per cent to 50 per cent with effect from 1 July 1993 and PRT was abolished for fields approved after 15 March 1993. |
|
Corporation Tax (CT), which is charged on the profits of oil and gas companies in much the same way as any other industry. In the case of new fields, this is now the only tax on profits. The main rate of CT is currently, at 30 per cent, one of the lowest company tax rates in the world. Both Royalty and PRT are deductible in computing profits for CT purposes. Profits from upstream oil and gas activities are ring-fenced so that they cannot be reduced for CT purposes by any losses or reliefs arising from any other activity, including downstream oil and gas operations. |
3.28 The tax regime which applies to any particular oil field therefore depends on the date on which it received development consent. Current marginal rates of tax vary between 69.4 per cent and 30 per cent depending on the age of the field in question and its taxable position (though it should be noted that many smaller, less profitable fields pay no PRT, even though they are in principle within the PRT net):
69.4% if liable to Royalty, PRT and CT
(approved before 1 April 1982 and in a PRT-paying position)
38.8% if liable to Royalty and CT
(approved before 1 April 1982 and shielded from paying PRT by allowances or other reliefs)
65.0% if liable to PRT and CT
(approved between 1 April 1982 and 15 March 1993 and in a PRT-paying position)
30.0% if liable only to CT
(approved between 1 April 1982 and 15 March 1993 and shielded from paying PRT by allowances or other reliefs or approved after 15 March 1993)
3.29 Responsibility for policy on oil and gas taxation matters lies with Inland Revenue and the Treasury but officials in DTI’s Oil and Gas Directorate play an important role by contributing technical assistance and detailed information and taking the lead on Royalty policy. PRT, CT and Royalty are collected and administered by the Inland Revenue’s Oil Taxation Office.
Production on the Banff field
Courtesy of Conoco (U.K.) Limited
3.30 No changes to the structure of North Sea taxation were announced in the March 2001 Budget. However, the Chancellor introduced proposals for a number of technical changes to the fiscal regime applying to the upstream oil and gas industry. Finance Bill 2001 includes provisions:
|
to close two PRT loopholes relating to expenditure on decommissioning oil installations; |
|
to extend PRT relief in respect of decommissioning installations in fields producing gas, which was exempt from PRT, to take fairer account of the use of those installations by other fields in return for tariffs which were liable to PRT; and |
|
to make capital allowances available for the costs of preparing oil installations for re-use and for removing and mothballing them when their eventual fate is unknown. |
3.31 In March 2001 the Secretary of State announced that the Government had agreed a Royalty Remission arrangement with Talisman, which will help the Beatrice redevelopment project to proceed. The Government did not believe that Talisman would progress their plans without the offer of remission of Royalty on future production. The Department is open to further discussions on Royalty Remission with any operator who has a strong enough case.
3.32 OG’s Oil and Gas Measurement Team (OGMT) has responsibility for developing UK policy on oil and gas measurement and for ensuring that licensees’ fiscal measurement systems comply with the requirements set out in UK Petroleum (Production) Regulations. All revenue generated by UKCS oil and gas production is calculated on the basis of the figures generated by these metering systems.
3.33 Twenty four sites were visited by Petroleum Measurement Inspectors during 2000. Thirteen of these were offshore. Two Trainee Measurement Inspectors were recruited in November and December 2000. This will allow an increased level of inspection during 2001.
3.34 OGMT has continued to co-operate with its Norwegian counterpart, the Norwegian Petroleum Directorate (NPD). A new Memorandum of Understanding for the measurement of fluids from the Ekofisk and Frigg pipeline systems was agreed in the course of 2000.
Back
| Title
| Table of Contents
Chapter 1 | Chapter 2 | Chapter 3 | Chapter 4
Appendix 1 | Appendix 2 | Appendix 3 | Appendix 4 | Appendix
5 | Appendix 6 | Appendix 7 | Appendix 8 | Appendix 9
Appendix 10 | Appendix 11 | Appendix 12 |
Appendix 13 | Appendix 14 | Appendix 15 |
Appendix 16 | Appendix
17
Index Map | Plate 1 |
Plate 2W | Plate 2E | Plate 3W | Plate 3E | Plate
4W | Plate 4E | Plate 5W | Plate 5E | Plate 6
Plate 7 | Plate
8W | Plate 8E | Plate 9W | Plate 9E | Plate 10W | Plate
10E | Plate 11 | Plate 12 | Legend
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