Chapter 3 - Regulatory Regime

3.1 The prominence given to protecting the environment from oil and gas exploration and development has increased considerably over the years and DTI takes its environmental responsibilities seriously. Environmental safeguards applicable to all stages of oil and gas exploitation have been developed. These are kept under continuous review and further improvements to the offshore environmental regime are planned. DTI liaises closely with other Government Departments and Agencies in developing its environment strategy.

3.2 DTI’s aim is to see that all activity on the UKCS, existing and new, is carried out in a proper manner which ensures that impact on the environment is minimised. All companies seeking to operate on the UKCS are required to carry out environment assessments of their proposed workplans and submit these to the Department before projects are allowed to go ahead. Environmental considerations are taken into account right from the start of any Licensing Round when the areas to be offered for licence are decided.

3.3 In support of licence applications, applicants must submit copies of their Company Environmental Policy and Environmental Management System together with an Environmental Assessment of the block(s) applied for. They must also demonstrate how their work programme will take environmental considerations into account. The applicant’s UK environmental record is also considered or its record overseas if the company is new to the UKCS.

3.4 Once an operator has begun to explore for or produce hydrocarbons they must comply with any relevant legislation. DTI ensures that this happens through a combination of exemption conditions and inspections and also through the development consent process. The Secretary of State’s permission is required before developments can proceed. They are very carefully planned and the DTI is involved in the process from and early stage. The approval process is a powerful tool for ensuring that the Operator, through intelligent design and selection of material and technologies, minimises the potential for adverse environmental impact or for pollution to occur.

3.5 The Department employs offshore environmental inspectors. They visit offshore production installations to verify that good oil field practice is being employed. These inspectors will also carry out the offshore investigation of any oil spills or other incidents where the Department has a responsibility.

3.6 The Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations to implement the EU Environmental Impact Directive were introduced in 1998 making Environmental Impact Assessments (EIAs) mandatory for all field developments. An EIA for exploration, appraisal and development wells is discretionary although in practice it is likely that any well in a sensitive area will be subject to the EIA process. This was a positive development ensuring that EIAs are given greater prominence and that operators are focused on improving their environmental analysis and delivery.

3.7 In 1999, the Department carried out public consultation on further improvements that could be made to the offshore environmental regime including the introduction of additional regulatory controls. The first is the introduction of Integrated Pollution Prevention and Control for large combustion plant, operating on offshore installations, which will be in force by summer 2000. Also expected in 2000 are two further sets of regulations to implement recommendations from Lord Donaldson’s Report in relation to oil spills from offshore installations and to introduce mandatory controls for chemicals used offshore and discharged into the marine environment.

3.8 A Court Judgement in 1999 that the EU Habitats Directive applies offshore, beyond the 12 mile limit, has important implications for offshore oil and gas. The DTI is considering how its obligations under the Directive should best be met.

3.9 Chart 3.1 shows data on oil spilled during the period 1990 to 1999 while Table 3.1 shows the reported figures. It is encouraging to note that the 1999 figure for accidental oil spills (120 tonnes) is lower than that for 1998 (137 tonnes). It is evident that the trend for reporting even the smallest of spills continues, with 352 reports for spills of less than 1 tonne: this represents 94% of reports. In addition to an ongoing prosecution in the English Courts two other oilspill incidents are under investigation.

	1990	1991	1992	1993	1994	1995	1996	1997	1998	1999
Total Amount Spilled (tonnes)	899	192	225⁽²⁾	224	174	84⁽³⁾	127	866⁽⁵⁾	137⁽⁶⁾	120⁽⁷⁾
Of which:
Oil from oil-based mud spills	466⁽¹⁾	116	49	145	74	29	28	38	35	3
Other oil spills	423	76	176	79	100	55	99	828	102	117
Number of Installations Reporting Spills	56	39	43	43	50	52	77	96	101	112
Total Number of Reports	345	234	194	183	147	145	300⁽⁴⁾	349⁽⁴⁾	392⁽⁴⁾	372⁽⁴⁾
Total Stabilised Crude Oil Produced from Offshore Oilfields (million tonnes)	86.3	83.1	89.1	90.2	114.4	116.7	116.7	115.3	119.1	124.0

3.10 Since 1986 the UK has carried out surveillance flights over offshore installations in accordance with international obligations under the Bonn Agreement. These flights are unannounced and cover all offshore installations (drilling rigs and production facilities) on the UKCS.

3.11 In 1999, 300 hours were spent on 54 ‘dedicated’ oil rig patrols i.e. funded solely by the DTI. In total 3,097 surveys of installations were undertaken. The total amount of oil observed from unreported spills was just over 2 tonnes from 40 separate detections. The Scottish Fisheries Protection Agency also undertakes its own routine overflights of the UKCS.

3.12 The Department continues to use the computer link to the aerial surveillance aircraft which transmits photographic images of pollution incidents and therefore enables the Department to investigate oil spill incidents as they happen. The Department is also looking at ways of improving the current surveillance programme and hopes to introduce changes within the next few months.

3.13 The programme of environmental inspections continued in 1999. Inspectors generally found that performance was satisfactory. Concerns, where evident, generally related to document control, the quality of environmental management systems, produced water sampling and analysis and chemical storage and usage. Such inspections are important to reassure the public that the environmental regime is applied properly offshore and for operators to demonstrate its effective application. It is planned to increase the number of inspectors available for this work.

3.14 In the UK, targets for oil discharges are regulated by conditions attached to exemptions issued under section 23 of the Prevention of Oil Pollution Act 1971 (POPA) for produced water and other operational discharges. These targets are agreed by the Oslo and Paris Commission, an international body charged with the prevention of pollution in the North-East Atlantic, which has indicated maximum target concentrations of oil from offshore oil and gas installations which should not normally be exceeded.

3.15 A mixture of oil, water and gas can be produced from reservoirs and these components are usually separated in the production train. However, not all the oil can be separated and as a result a small quantity of oil is discharged with the produced water.

3.16 When the discharge of oil-contaminated produced water from offshore installations is permitted by an exemption granted under POPA, the oil content must not exceed 40 parts per million. It has proved to be difficult for a few installations, in particular those operating in mature fields, to meet this target. In 1999, of 73 installations discharging produced water, 3 exceeded this target when averaged over the whole year. The average content of oil in produced water for the year, for the UKCS as a whole, was 21.5 parts per million. This is an improvement on last year’s figure of 22 parts per million and is the lowest value yet recorded.

3.17 This continues a downward trend in recent years and is a real achievement for the offshore oil industry as the amount of water produced with oil increases as fields mature. This reduction highlights the considerable efforts being made by both Government and industry in minimising the oil in produced water discharges. Every installation’s produced water discharge is different and as such there is no single solution to reducing oil discharges. Industry must ensure there is a continued effort to improve performance. Table 3.2 shows the amount of oil discharged with produced water; with the downward trend shown in Chart 3.2.

	1990	1991	1992	1993	1994	1995	1996	1997	1998	1999
Total Oil Discharged (tonnes)	4393	5490	4850	4232	4418	5855	5706	5767	5692	5641
Total Water Discharged (million tonnes)	159	153	135	148	147	192	210	234	253	261
Number of Installations Permitted to Discharge Oil	39	39	43	46	52	55	60	64	64	73
Average Oil in Water Content (mg/kg)	27	35	36	28	30	30	27	25	22	22
(1)Actual figure is 21.5 mg/kg

3.18 Following the introduction of controls on the discharge of mineral oil-based cuttings, there was an increase in the use of ‘synthetic’ or ‘pseudo’ oil-based muds. Following concerns raised about the environmental acceptability of some of these products, studies of several of the commonly used synthetic fluids showed that their biodegradation properties were very similar to those of the mineral oils they had replaced. DTI, in conjunction with other Government Departments therefore acted with operators to reduce the discharge of those unacceptable synthetic drilling fluids to zero by 31 December 2000. In order to achieve this, all operators were asked to draw up a company specific phase-out strategy demonstrating how each company intends to reduce its discharges by approximately 20% each year using a 1996 baseline. Operators are required to resubmit strategies each year to provide actual discharge figures as well as ensuring reduction targets are updated for forthcoming years. The objective of zero discharge by end-2000 is expected to be achieved and companies are making greater reductions than targeted.

3.19 The Department is concerned to avoid the unnecessary and wasteful flaring and venting of gas and is keen to promote a policy of best environmental practices. It will seek to reach aggreement with Licensees for consent levels that are not unduly restrictive but are the minimum that are economically reasonable. Under the terms of petroleum production licences, gas may be flared only with the consent of the Secretary of State. During 1999 an average of 5.76 million cubic metres of gas a day was flared at offshore installations. This represents a rise of 3.7% over 1998, and is primarily accounted for by high production and new fields coming onstream. Flaring at onshore fields was minimal during 1999.

3.20 The United Kingdom is determined to play a constructive role in continuing international efforts to deal with the threat of climate change.

3.21 The UK has an international, legally-binding target for the reduction of its greenhouse gas emissions, following the agreement of a Protocol to the United Nations Framework Convention on Climate Change (UNFCCC), at Kyoto in December 1997, and the subsequent EU burden sharing agreement, agreed by Member States in June 1998. The UK’s target is to reduce its emissions of a basket of six greenhouse gases - carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride - by 12.5% from 1990 levels, during the period 2008-2012. The EU also agreed, in June 1998, priorities for action on common and co-ordinated policies and measures, to be pursued at EU and national level.

3.22 The 5th Conference of the Parties to the UN Framework Convention on Climate Change (COP5) was held in Bonn between 25 October and 5 November 1999. COP 5 prepared the ground for COP6, to be held at the Hague in November 2000, where key follow up decisions to the Kyoto Protocol are due to take place. These will include decisions on issues such as a compliance regime for Kyoto and the rules for operation of the Kyoto mechanisms, including international emissions trading. Discussion papers were written that will form the basis of negotiations up to COP 6. There was also progress on the procedures for the Kyoto mechanisms and compliance arrangements. There was agreement on an intensification of the negotiating process in the period leading up to COP6, which was scheduled for November 2000.

3.23 The Government conducted a consultation between October 1998 and February 1999 on possible policies and measures for achieving the UK’s Kyoto target; and also for moving towards the domestic policy goal of a 20% reduction in CO2 emissions by 2010. It is now considering the responses to the consultation and will be developing a national climate change programme, which was published for further consultation on 9 March 2000.

3.24 A key element of the climate change programme will be the new climate change levy on business. The Chancellor announced the proposals for the levy in the Budget of 9 March 1999. He subsequently elaborated these proposals in his pre-Budget report of 9 November 1999, and his March 2000 Budget Statement following extensive consultation of business and other interested parties. He confirmed that the levy rates in 2001-02 will be 0.43 pence per kilowatt hour for electricity, 0.15p/KWh for gas and 0.15p/KWh for coal. The levy revenues are projected to be £1 billion in 2001-02. The revenues will be recycled to business, primarily via a 0.3 percentage point cut in employer National Insurance contributions. There will be £150 million of revenues earmarked in 2001-02 for support to energy efficiency measures for business, including a new system of 100% first year capital allowances for energy saving investments. There are exemptions from the levy for electricity generated from new renewable sources and from good quality combined heat and power plant. In order to protect the international competitiveness of energy intensive industries, there will be 80% levy discounts for sectors with sites regulated under the EU Integrated Pollution Prevention and Control Directive which enter negotiated agreements with the Government to improve their energy efficiency or to cut emissions.

3.25 The Government is also encouraging the development of emissions trading in the UK. An industry-led initiative, the Emissions Trading Group has been developing outline proposals for a UK emissions trading scheme, with the aim of it starting up in 2001.

3.26 The UK’s legal framework for petroleum licensing is founded on the premise that ownership of the petroleum resources of Great Britain and the territorial sea is vested in the Crown and the Government has the right to grant licences to explore for and exploit these resources as well as those on the UKCS.

3.27 There are separate licensing regimes for landward and seaward areas. 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 awarded and the criteria to be taken into account in making licence awards. The Government is committed to ensuring that the licensing regime remains flexible and responsive to the changing needs of the oil and gas industry and of the nation.

3.28 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 Darrell Sime Tel: 020 7215 5173).

3.29 The Department of Trade and Industry is responsible for the implementation and development of Government policy on decommissioning offshore oil and gas installations and pipelines.

3.30 The primary legislation which regulates the disposal of redundant installations and pipelines is the Petroleum Act 1998 (the 1998 Act).

3.31 The 1998 Act 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 will be jointly and severally liable to submit a decommissioning programme for Ministerial approval and ensure that the provisions of the programme are implemented.

3.32 At the first Ministerial Meeting of the OSPAR Commission which supervises the implementation of the Convention for the Protection of the Marine Environment of the North East Atlantic in July 1998 a binding Decision (Decision 98/3) was agreed which set the rules to be applied to the disposal of offshore installations at sea.

3.33 Under the Decision, which entered into force on 9 February 1999, there is a prohibition on the dumping and leaving wholly or partly in place of offshore installations. The Decision recognises that there may be difficulty in removing the ‘footings’ of large steel jackets weighing more than 10,000 tonnes and in removing concrete installations. As a result there are derogations for these categories of installations if the internationally agreed assessment and consultation process shows that leaving the footings of a large steel installation or leaving a concrete installation wholly in place is justifiable. The Decision will be reviewed in 2003 at the next Ministerial Meeting of OSPAR.

3.34 The full OSPAR Decision 98/3 is available from the OSPAR website: http://www.ospar.org

3.35 The UK Offshore Operators Association (UKOOA) is currently co-ordinating a Joint Industry Project (JIP) studying the issues associated with the accumulation of drill cuttings beneath some offshore installations. The objective of the initiative is ‘to identify the best environmental practice and the best available techniques in accordance with the principles set out by the OSPAR Commission’. The UK Government is committed to reporting the UKOOA findings to the OSPAR Working Group on Sea Based Activities (SEBA) which is considering the environmental impact of, the need for, and the possible means for, cleaning up seabeds contaminated by oily cuttings. The information generated by this study will be useful in the consideration of decommissioning programmes.

3.36 Stage 1 of the JIP has been completed. The results have identified areas that require further research. Stage 2 is under way and will include offshore trials during summer 2000.

3.37 ‘Guidance Notes for Industry covering the decommissioning of offshore installations and pipelines under the Petroleum Act 1998’ were issued for consultation during 1999. This consultation attracted a positive response. The Department is currently assessing the comments with the aim of issuing the final version of the guidance notes by the middle of 2000.

3.38 The North Sea fiscal regime is one of the main mechanisms for capturing for the nation the economic benefit from the UK’s oil and gas resources. The special UKCS tax regime is designed to extract an appropriate share of profits for the nation while offering stable, attractive and economically sound investment conditions to the oil industry. Like the licensing system, the tax system has developed over time. It is kept under continuous review and many adjustments have been made to it to reflect changes taking place in the UKCS.

3.40 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):

3.41 Responsibility for policy on oil and gas taxation matters lies with the 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 (since April 2000) royalty are collected and administered by the Inland Revenue’s Oil Taxation Office. The transfer of royalty collection functions to the Inland Revenue was carried out in order to consolidate the administration of all Government revenue collection for UK oil and gas production and provide the industry with a more streamlined service.

3.42 Following strong representations from the oil industry, with effect from 1 July 1999 the Government extended capital gains roll-over relief to oil licences. This measure ensures that when companies dispose of an interest in a UK oil licence, and re-invest the proceeds in another licence or other North Sea asset, they will not face an immediate tax charge on any capital gain. Reducing the tax charge on such transactions in this way will make it easier for field owners to rationalise their holdings of North Sea licences through swaps or acquisitions, allowing consolidation of interests and more cost-effective development. The number of asset swaps is expected to increase significantly, stimulating increased investment and activity. This change was widely welcomed as a tangible sign of continued Government commitment to the future of the industry.

3.43 No changes to the structure of North Sea taxation were announced in the year 2000 Budget on 21 March. 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 2000 includes provisions:

3.44 As part of DTI’s Oil and Gas Directorate, the Oil and Gas Measurement Team (OGMT) has responsibility for ensuring that Licensees comply with measurement requirements set out in UK Petroleum (Production) Regulations. OGMT is also responsible for UK policy on Oil and Gas Measurement.

3.45 Some 36 sites were visited by Petroleum Measurement Inspectors during 1999. 26 of these were offshore. 66 separate metering systems were inspected. It is anticipated that the level of inspections will increase in the year 2000. In general, the level of compliance was found to be high, although there were some instances where the inspections revealed deficiencies in the measurement of petroleum.

3.46 The last 12 months have seen some important developments in oil and gas flow measurement, notably the increased use of ultrasonic meters. OGMT has been active in encouraging the deployment of new technology to help identify ways of reducing operating costs while retaining measurement integrity.

3.47 OGMT has continued to co-operate with its Norwegian counterpart, the Norwegian Petroleum Directorate (NPD), in order to maximise the efficiency of measurement regulation in areas of joint interest such as common transportation systems and trans-median fields. The annual NPD/DTI Measurement Liaison Meeting took place in Aberdeen, in November 1999.

	Royalty, which is paid, as a condition of each oil production licence, at 12 1/ 2 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 rewards. 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.