The UK oil and gas industry continues to experience an overall upturn in the first half of 2018, relative to recent years. Capital expenditure in the industry was relatively low in 2017, and it had been forecast that fresh investment in 2018 could see capital expenditure increase for the first time in four years. Although the low level of new project and drilling activity continued into the first six months of 2018 there is some cause for optimism with six major new project final investment decisions being made in the first eight months of 2018.2 The turbulent times of the past few years have prompted some positive trends in market performance. Development efficiency has improved, with projects routinely completing on time and under budget, and production efficiency has risen for a fifth consecutive year. The rising oil price, which hit US$70/bbl in early 2018 for the first time in three years, has provided a welcome boost to margins for exploration and production companies.

The past two years have also seen renewed optimism and a significant upturn in M&A activity with the re-emergence of private equity investment. There has been a general trend towards divestment from the major players, and investment from smaller independent companies through private equity finance, with a healthy variety of deal types and sizes last year and investment in the UK continental shelf (UKCS) continuing to rise. Looking back on 2017, the value of UK upstream mergers and acquisitions surpassed US$8 billion, which represents continuing confidence in the UKCS.3

The UKCS is still a significant basin in terms of production, which the Oil and Gas Authority estimates will total 11.7 billion barrels of oil equivalent (boe) over the period from 2016 to 2050, 2.8 billion boe higher than prior estimates. There are a number of undeveloped fields in the UKCS, with geological surveys showing 20 billion boe yet to be recovered,4 and significant exploration upside in harsher operating areas like West of Shetland. The government is encouraging investment in these exciting prospects through policy decisions, including relaxed licence conditions, and financial incentives, like the current proposal to allow the assignment of tax history between incoming and outgoing licence holders (see detailed explanation in Section VIII).


The primary legislation that sets out the regime under which petroleum is explored for, developed and produced in the UK is the Petroleum Act 1998 (as amended) (the Petroleum Act). Since 1934, there have been various pieces of legislation governing the rights to exploit petroleum in the UK, all of which are currently consolidated in the Petroleum Act. Under the Petroleum Act, ownership of petroleum vests in the Crown with Her Majesty having the exclusive right to explore for and develop onshore and offshore petroleum resources. Crude oil, gas and shale gas all fall within the definition of petroleum in the Petroleum Act and are governed by the same regime.

The Petroleum Act operates a licence regime under which licences are granted to persons to 'search and bore for and get' petroleum. The holder of a licence is granted the right to explore and develop a geographical licence area in return for a fee. If the licence holder successfully develops an oil or gas field, ownership of the petroleum within the licence area transfers from the Crown to the licence holder at the well head. The rights and obligations of the licence holder are contained both within the conditions of the licence and applicable laws (see detailed explanation below).

Historically, the Department of Energy and Climate Change (DECC) and the Secretary of State were together responsible for energy policy, regulation of the UK's petroleum resources and oversight and implementation of the licensing regime. This changed in 2014, when the Wood Review recommended fundamental changes to the management and oversight of the UK petroleum regime, aimed at incentivising investment and ensuring that the petroleum industry remained relevant. One of the consequences of the Wood Review was the creation of a new department to replace DECC – the Department of Business, Energy and Industrial Strategy (BEIS) – and the creation of a new regulator – the Oil & Gas Authority (the OGA) – responsible for licensing on behalf of the Secretary of State and BEIS.

The OGA was initially established as an executive agency of BEIS. However, the Energy Act 2016 established the OGA as a fully independent regulatory body for both onshore and offshore petroleum resources, in the form of a company in which the Secretary of State for BEIS is the sole shareholder. The Energy Act 2016 also amended the Petroleum Act to assign to the OGA certain functions and powers that were previously held by the Secretary of State, and to vest the OGA with new powers, including the ability to:

  1. participate in non-binding dispute resolution procedures, including disputes in relation to third party access to upstream petroleum infrastructure;
  2. request information and data from participants in the industry;5
  3. attend the meetings of participants in the industry; and
  4. sanction industry participants for failure to comply with defined petroleum-related requirements (such as a failure to comply with the terms or conditions of an offshore licence). Sanctions include financial penalties up to £1 million, licence revocation and the removal of the petroleum field operator.

The relationship between BEIS and the OGA is governed by a framework agreement. While many powers have been transferred to the OGA, the Secretary of State still has overall responsibility for energy policy and is responsible to the parliament for the OGA.6 BEIS has retained responsibility for the regulation and enforcement of the environmental regime and decommissioning obligations. HM Treasury continues to be responsible for fiscal matters, and HM Revenue & Customs retains responsibility for tax retrieval. Other relevant bodies include the Health and Safety Executive (which is responsible for enforcing the health and safety regime), the Hazardous Installations Directorate (which regulates and promotes improvements in health and safety in offshore petroleum projects, regulates the natural gas supply industry, and regulates onshore and offshore pipelines) and the OSPAR Commission (which oversees the UK's international obligations on the protection of the marine environment and decommissioning).

The Maximising Economic Recovery Strategy for the UK (MER UK Strategy), was produced by the Secretary of State in consultation with the industry and came into force in March 2016. The guiding principle of the MER UK Strategy is that:

relevant persons must, in the exercise of their relevant functions, take the steps necessary to secure that the maximum value of economically recoverable petroleum is recovered from the strata beneath relevant UK waters.

The Infrastructure Act 2015 is the legislative basis for implementing the MER UK Strategy. It amended the Petroleum Act by inserting a requirement to maximise the economic recovery of UK petroleum, through (among other things) collaboration between licence holders and the owners of upstream petroleum infrastructure.

The Petroleum Act is the principal legislation that applies to both the UK's land (the landward or 'onshore' regime), and the UK's territorial waters and continental shelf (the seaward or 'offshore' regime). UK territorial waters extend for 12 nautical miles from the low water mark as set out in the Territorial Sea (Baselines Order) 2014 (following the principles laid down in the Geneva Convention on the Territorial Sea 1958). In 1964, the UK ratified the Geneva Convention on the Continental Shelf 1958 and designated an area in the North Sea as the UKCS, which has, since then, been redefined a number of times further to boundary treaties with Belgium, Denmark, France, Germany, Ireland, the Netherlands and Norway. The Continental Shelf (Designation of Areas) Order 2013 replaces previous orders and designates what is now deemed to be the UKCS.


The Petroleum (Transfer of Functions) Regulations 2016 vested in the OGA the exclusive right and responsibility to grant licences to explore for, develop and produce petroleum resources.7 Under the licence regime of the Petroleum Act, applications are made for licences to the OGA as part of an annual competitive licensing round. The licensing round is advertised on the OGA website and in the European Journal. The OGA also has an out-of-round application process typically initiated at a company's request, through which the OGA grants licences over small areas, in exceptional circumstances.

The Petroleum Licensing (Applications) Regulations 2015 contain the application process for licences. All applications must be made in the prescribed form and for a specific area. A company can apply on behalf of itself or a joint venture. There are no express restrictions on foreign ownership, however, all applicants must be registered in the UK, either as a company or as a branch of a foreign company to ensure that they have a taxable UK presence. The UK does not have a national petroleum company and the government cannot directly make an application for a licence.

The OGA considers all applications on an individual basis and expects companies to meet certain financial and technical capability requirements. Licensees will need to have the financial ability to fulfil their obligations under the licence and complete the relevant work programme or proposed development. Each licence is required to have an operator to manage and supervise the exploration and development of the petroleum field. The operator requires the approval of the OGA as part of the licence application process. Where a company is taking on the responsibility of operatorship, it will need to have the technical capability to perform the role. Non-operators still require technical expertise sufficient to exercise responsible oversight of the project. There are also other requirements for licensees under the Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015 (see Section VI).

In awarding licences, the OGA must comply with the Hydrocarbons Licensing Directive Regulations 1995, which implements certain EU directives in relation to petroleum licensing, including factors that may (or may not) be taken into account when deciding whether to issue a licence, and the minimum amount of public consultation required.

The OGA runs separate licensing rounds for onshore and offshore licences. On 10 July 2018, the OGA launched the 31st Offshore Licensing Round, offering a total of 1,766 blocks (370,000km²) of open acreage in frontier areas of the UKCS. Following the level of interest in the 30th Offshore Licensing Round, companies were also provided with the opportunity to nominate additional blocks in mature areas. The last onshore licensing round was held in 2014, with licences for 159 blocks being awarded as part of the 14th Landward Licensing Round. Except for the manner in which the licence areas are designated, the onshore and offshore regime are remarkably similar. The principal differences are the need for an onshore operator to comply with the environmental and planning laws that apply to England and Scotland and the recent devolution in Scotland and Wales of the OGA's powers in respect of the licensing of onshore petroleum activities to the Scottish and Welsh Ministers respectively.

The UK licence takes the form of a deed, pursuant to which the licensee agrees to be bound by the terms of the licence and observe the general conditions of the licence. The conditions of the licence, also referred to as 'model clauses', are contained in secondary legislation, which are then incorporated into the licence. Up to the 19th licensing round, the model clauses were incorporated into licences by means of a single short paragraph. From the 20th round onwards the model clauses have been set out in full in the licence itself, for the sake of clarity. These model clauses include details such as the term, licence area relinquishment, minimum work obligations, appointment of the operator and record keeping. Existing licences are not affected by the issue of subsequent sets of model clauses (except through specifically retrospective measures).

The secondary legislation applying to current licences are:

  1. the Petroleum Licensing (Exploration and Production) (Seaward and Landward Areas) Regulations 2004 for exploration licences, production licences and petroleum exploration and development licences for the 22nd and subsequent licensing rounds (offshore) and the 12th and subsequent licensing rounds (onshore);
  2. the Petroleum Licensing (Production) (Seaward Areas) Regulations 2008 for offshore production licences for the 25th and subsequent licensing rounds; and
  3. the Petroleum Licensing (Exploration and Production) (Landward Areas) Regulations 2014 for onshore petroleum exploration and development licences issued in the 14th onshore licensing rounds, as well as new onshore exploration licences (see below).

Licences can be held by a single company or by several working together, but in legal terms there is only ever a single licensee despite the number of companies it may represent. All companies on a licence share joint and several liability for operations conducted under the licence. The Petroleum Act does not limit the liability of the licensee. Where more than one company forms the licensee, the companies will enter into a joint operating agreement and form an unincorporated joint venture to govern the relationship between them and apportion liability, costs and revenue. Such apportionment of the risk and reward under the licence requires the OGA's approval.

The most common types of licences are as follows.

i Exploration licence

This grants the licensee a non-exclusive right to carry out exploratory seismic or other surveys over relatively large geographical areas not already covered by a production licence. These are typically used by seismic contractors who wish to gather data to sell rather than to exploit the petroleum resources themselves. There are two types of exploration licence: one for offshore areas and one for onshore areas. As exploration licences are not exclusive, companies can apply at any time for a new exploration licence (or for an extension to an existing exploration licence). The licensee pays a flat rental charge for the exploration licence.

ii Petroleum exploration and development licence

The onshore production licence is known formally as a petroleum exploration and development licence (PEDL). Licensees are granted the exclusive right to explore for and develop petroleum in a specified onshore area. Each licence carries an annual charge, called a rental. Rentals are due each year on the licence anniversary and are charged at an escalating rate on the area of the licence at that date. The PEDL runs for three successive terms or phases. The initial term is typically for five years and is the period during which the licensee performs the exploration work programme that it has agreed with the OGA during the licensing round. The licence will expire at the end of its initial term unless varied by agreement or the licensee has completed the work programme and relinquished 50 per cent of the initial licence area. The second term usually lasts for five years and is associated with appraisal and development. The licence will expire at the end of its second term unless varied by agreement or the OGA has approved a field development plan. The third term is for 20 years and intended for construction of facilities and production. The OGA may extend the term if production is continuing.

iii Seaward production licence

This is the umbrella name for three types of offshore licences under which licensees have been granted an exclusive right to explore for, develop and produce petroleum fields from the UKCS for future grants. These three types of offshore licences will be replaced by the 'innovate licence' for future grants (see below), but remain relevant for the majority of existing offshore production licences.

The 'traditional licence' is the most common offshore production licence. The initial exploration phase is typically for four years, during which the licensee must complete the minimum work programme. The licensee must relinquish 50 per cent of its acreage at the end of this phase, if it wishes to move onto the next phase. The second appraisal phase is also for four years, during which the licensee will need to submit its field development plan for approval by the OGA (the OGA published revised guidance on the requirements for UKCS field developments in May 2018). The final production phase typically has an 18-year term with the possibility to extend the term if production is continuing. An annual rental is payable, charged on the area of the licence. Like the PEDL, rental escalates each year after the initial exploration phase.

The 'promote licence' was introduced to allow smaller and start-up companies to obtain an offshore production licence first and gain the necessary operating and financial capacity later. The term of the various phases and the relinquishment obligations are the same as a traditional licence. However, during the first two years, the operatorship competence criteria (financial and technical capability requirements) for licensees are relaxed, and the annual rental rate is reduced by 90 per cent. The licence terminates if the licensee is not able to establish the requisite financial, technical and environmental capabilities, or the licensee has failed to make a firm drilling commitment (or agreed equivalent equally substantive activity) by the end of the initial two year period.

The 'frontier licence' was introduced to address the complexities in sourcing petroleum in remote areas of the UKCS and to allow for exploration over a larger area. The licensees benefit from an extended period to acquire seismic data in comparison to a traditional licence, during both the initial exploration phase (two more years for standard frontier licences and five more years for the harsher West of Shetland frontier licence) and the second appraisal phase (two more years for both types of frontier licence). The licensee has to relinquish 75 per cent of the acreage at the end of the third year of the initial exploration phase, and a further 50 per cent of the remaining area at the end of the initial exploration phase. Like promote licences, the operatorship competence criteria will not be applied to frontier licence applications for the first two years and the annual rental rate is reduced by 90 per cent for the first two years.

iv Offshore innovate licence

The 29th Licensing Round signalled the launch of a new type of offshore production licence called the 'innovate licence'. The OGA announced that this licence would replace all other types of offshore production licences for all future licensing rounds including the 30th Licensing Round. These changes to the offshore model clauses were implemented through The Petroleum and Offshore Gas Storage and Unloading Licensing (Amendment) Regulations 2017. The main difference between the innovate licence and older licences is the duration of the initial and second phase and the flexibility that licensees will have in determining the length of each phase. The initial term can be for up to nine years and the second term can have a duration of four years (the default position) but with a length of up to six years where technical challenges apply. The initial term will be divided into three phases: phase A – for studies and reprocessing; phase B – for acquiring new seismic data; and phase C – for drilling wells. The third term is usually 18 years, and may be extended for ongoing production.


Any transaction that results in a company joining a licence or a company leaving or withdrawing from a licence is deemed to be a licence assignment. Any assignment of a licence, including affiliate assignments, requires prior consent from the OGA. Assignments made without prior consent are seen by the OGA as a very serious breach of the licence and as grounds for immediate revocation of the licence or an unwinding of the transaction.

The OGA will review and consider the form of the deed of assignment used by the parties. The OGA provides approved draft deeds of assignment on its website. There is some room for movement, but material changes will increase the time for obtaining the OGA's consent.

Because an assignment requires prior consent, it is the existing licence holder who must apply to the OGA. Offshore licence assignments are processed through the Petroleum E-Business Assignments and Relinquishment system (PEARS), which forms part of the online UK energy portal. PEARS can be used by licensees to process several types of transactions: licence assignments, interest allocations, operator changes, licence administration changes, licence relinquishments and the surrender of acreage. Onshore licence assignments are still processed using an application form available on the OGA website, which also contains a guidance note on the information required in the application. Consent from the OGA lapses after three months, so completion of the relevant transaction must occur within that time, to avoid the need to request an extension.

When assessing an application, the OGA will consider matters including:

  1. the technical capability of the transferee;
  2. the financial resources available to the transferee (particularly if the licence has significant decommissioning obligations);
  3. intragroup assignments (the OGA will want to be made aware of whether the transfer is the first stage of a corporate disposal);
  4. change in operatorship; and
  5. the ability of the transferee to comply with the Offshore Safety Directive.

A change of control does not strictly require the OGA's consent, but will trigger powers of the OGA to require a further change of control or a revocation of the licence. As a result, ordinary practice is to apply to the OGA and seek comfort that the OGA will not exercise its powers. Any such application should demonstrate that the proposed transaction will not affect the ability of the licence holder to meet its obligations under the licence.

Creation of a charge over a licence requires the consent of the OGA. In 2012, the Secretary of State granted the Open Permissions (Creation of Security Rights Over Licences). Where the charge fits the description set out in the open permission, automatic consent is granted by the open permission and the licensee does not need to seek further individual approval from the OGA. However, in order to take advantage of the open permission, the licensee will need to notify the OGA of certain details of the charge within 10 days of its creation. Charges that are excluded from the open permission will need individual approval from the OGA. If the holder of a charge wishes to enforce the security interest it is a licence assignment and the normal licence assignment procedure will apply.


There are two different means through which the UK gets a return from the production of petroleum (onshore and offshore):

  1. annual rentals payable under each licence (see Section III); and
  2. taxes on the profits derived from petroleum production.

The current UK petroleum taxation regime is complex and has arisen out of the many changes that have taken place since specific petroleum tax provisions were first introduced in 1975. The government has recently attempted to simplify the regime in order to make the UK more attractive for foreign investments, including the proposal to allow the assignment of tax history between incoming and outgoing licence holders (see detailed explanation in Section VIII).

Until the Finance Act 2016, there were three main elements of taxation: petroleum revenue tax, ring fence corporation tax and supplementary charge. Petroleum revenue tax (PRT) is a field based tax charged on profits arising from individual petroleum fields, but only in respect of those fields given development consent before 16 March 1993. PRT was originally levied at 50 per cent. On 16 March 2016, the Chancellor of the Exchequer announced a permanent reduction in the PRT rate to zero per cent with effect from 1 January 2016. PRT was not abolished in totality to allow for losses to be claimed back against past PRT payments (for example payments incurred as a result of decommissioning PRT-liable fields).

The two remaining elements of the tax regime are:

  1. ring fence corporation tax (RFCT): This is the standard corporation tax applicable to all companies with the addition of a 'ring fence', which prevents taxable profits from petroleum extraction being reduced by losses from other activities or by excessive interest payments. Deductions are available for items such as capital expenditure, plant and machinery, allowances, research and development and decommissioning. The main rate of corporation tax in the ring fence has been fixed at 30 per cent since 1 April 2008; and
  2. supplementary charge (SC): This is an additional charge on a company's ring fence profits, introduced at 10 per cent on 17 April 2002. The SC was increased to 20 per cent in 2006 and 32 per cent in 2011. Following various fiscal reviews, the SC has been reduced a number of times and has been 10 per cent since January 2016. The concept of field allowances, which reduce the amount of adjusted ring fence profits on which the SC is charged, was introduced in 2009 to provide an incentive for the development of commercially marginal petroleum fields. These field allowances have now been replaced by a basin-wide investment allowance, which exempts a portion of a company's profits from the SC. The amount of profit exempt from the SC is equal to 62.5 per cent of the company's investment expenditure on the relevant field. Investment allowance is activated by generating relevant income (defined as production income from oil and gas extraction activities). On 23 July 2018, the government published draft regulations that propose to expand the scope of relevant income to include tariff receipts (being income received for the use of infrastructure by third parties) for the purposes of calculating the SC. The amendments, if passed, are intended to encourage investment in infrastructure.

A new levy on offshore petroleum exploration and production licensees has been created to provide funding for the OGA. The levy is payable by licence-holders for each licence they hold. The levy is apportioned between pre-production licences (11 per cent) and producing licences (89 per cent), the latter being those licences where the OGA has given consent to start production. Details of the levy for 2018/2019 are set out on the OGA website and in The Oil and Gas Authority (Levy) and Pollution Prevention and Control (Fees) (Amendment) Regulations 2018.


As well as being required to comply with all applicable laws, the model clauses generally require all licensees to operate in accordance with the methods customarily used in good oilfield practice and to take all steps practicable (a very wide concept) in order to prevent the escape or waste of petroleum (including into any waters in or near the vicinity of the licensed area).

The UK regulatory system for offshore installations is designed principally with accident and pollution prevention in mind. The main focus is to ensure that comprehensive measures are already in place so that an operator may anticipate any potential incident and act accordingly, rather than relying upon the authorities to dictate the appropriate response. The Merchant Shipping (Oil Pollution Preparedness, Response & Cooperation Convention) Regulations 1998, and the Offshore Installations (Emergency Pollution Control) Regulations 2002 (together the OPEP Regs) are the main components of the legal framework involving offshore installations. They impose obligations upon operators to implement robust emergency planning arrangements, and powers are reserved for the government to step in and take measures to enforce any necessary remedial actions. The Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (the OPPC Regs) and the Offshore Chemicals Regulations 2002 (the Chemical Regs) supplement the OPEP Regs by imposing a permitting system for oil and chemical discharges from an offshore installation, providing powers of remediation in the event of an unauthorised discharge, and providing powers to recover costs if the government has to intervene (should the operator fail to do so).

Following the Piper Alpha disaster8 and the Cullen Inquiry,9 the UK developed the Offshore Installations (Safety Case) Regulations 2005. The regulations require written safety cases and risk assessments to be prepared by the operator, and then approved by the Health and Safety Executive (the HSE), for all fixed and mobile offshore installations, before such installations are brought into use on the UKCS. The regulations also introduced:

  1. a system of well notification, where the HSE assesses well design and procedures;
  2. a requirement for the design and construction of a well to be examined by an independent specialist;
  3. a scheme of independent verification of offshore safety critical equipment (e.g., blowout prevention equipment) to ensure the equipment is fit for purpose;
  4. checks to ensure workers have received suitable information, instruction, training and supervision; and
  5. offshore inspections of well control and integrity arrangements, and related safety issues, by specialist inspectors from HSE's Offshore Safety Division.

Under the Energy Act 1976 and the Petroleum Act, the consent of the OGA is required for flaring and venting. There are also a number of other regulations that relate to flaring of gases, gas turbines and other combustion plants, including the Offshore Combustion Installations (Pollution Prevention and Control) Regulations 2013 (the Combustion Regs) (amended in 2018 to extend to large combustion plant with an individual thermal input of at least 50MW, and medium combustion plant with an individual thermal input of between 1 and 50MW) and the Fluorinated Greenhouse Gases Regulations 2015.

The Offshore Environmental Civil Sanctions Regulations 2018 will come into force on 1 October 2018, allowing the Secretary of State to impose civil sanctions (by way of fixed and variable monetary penalties) on operators that breach several of the environmental regulations mentioned above (the OPEP Regs, the OPPC Regs, the Chemicals Regs and the Combustion Regs). The power to impose civil sanctions will apply to acts or omissions occurring on or after 1 November 2018, with the associated standard of proof beyond the threshold of reasonable doubt. The regulations require the Secretary of State to prepare and publish guidance about the new powers by 1 November 2018, and to publish reports from time to time specifying the cases in which penalties have been imposed.

In the aftermath of the Deepwater Horizon disaster in 2010, the European Commission adopted the Offshore Safety Directive (2013/30/EU) (the 2013 Directive), to address inconsistencies in the regulation of petroleum activities between EU member states and to set out certain minimum requirements that could prevent catastrophic events. There were three stages to the implementation of the 2013 Directive: (1) by 19 July 2015, member states were to bring into force any legislation necessary to comply with the 2013 Directive; (2) by 19 July 2016, legislation (implementing the 2013 Directive) would need to start applying to owners and operators planning installations and those planning and executing well operations; and (3) by 19 July 2018 the legislation would need to start applying to all existing installations.

The European Commission decided to follow, to a large extent, the UK's highly respected environmental regime, and therefore many of the provisions of the 2013 Directive are already satisfied by the existing regulatory regime. However, a number of new laws were necessary to fully implement the 2013 Directive, including Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015, Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015 and the Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) (Amendment) Regulations 2015.

The 2013 Directive additionally required the creation of an offshore competent authority, which was established in the UK as the Offshore Safety Directive Regulator. The role of the Offshore Safety Directive Regulator is to supervise compliance with the 2013 Directive and undertake regulatory functions such as accepting, assessing, approving and inspecting relevant safety cases, oil pollution emergency plans, well notifications and other notifications. BEIS retains responsibility for regulation and enforcement of the environmental regime.

The European Commission is currently assessing whether the 2013 Directive has achieved its objective of ensuring safe offshore oil and gas operations. The scope of the evaluation, as set out in an evaluation road map released on 3 May 2018, includes an assessment of gaps in safety legislation. The planned completion date for the evaluation is mid-2019.

In the event of an oil pollution incident in UK waters, the licensees will have unlimited liability for all remediation under the EU Environmental Liability Directive (2004/35/EC). In addition to a licensee's remediation obligations, under English law, liabilities may arise under such actionable wrongs as nuisance and negligence. The alternative and much more straightforward basis for recourse available to third parties, in the event of their suffering damage caused by operations of an offshore installation (including for onshore and offshore clean-up operations, property damage and certain other quantifiable losses), is to make a claim under the offshore pollution liability agreement (OPOL). All offshore operators currently active in exploration and production on the UKCS are party to this voluntary oil pollution compensation agreement. Operator membership of OPOL is a prerequisite condition of OGA granting a licence, so in practice, despite its voluntary status, membership of OPOL is unavoidable for operators. Under OPOL, operators are subject to strict liability (where proof of fault is not necessary) for pollution damage and the cost of remedial measures up to a maximum of (currently) US$250 million per incident.


Decommissioning is primarily governed by the Petroleum Act, which imposes a clear requirement on licensees to pay for offshore installations to be properly decommissioned and completely removed from the seabed other than in exceptional circumstances. As noted above, BEIS retains responsibility for the regulation and enforcement of decommissioning obligations. Responsibility within BEIS rests with the Offshore Petroleum Regulator for Environment and Decommissioning (OPRED).

Section 29 of the Petroleum Act gives the Secretary of State the power to serve a notice (a Section 29 Notice) that either specifies a date by which a decommissioning programme is to be submitted (for each installation or pipeline) or, as is more usual, provides for a decommissioning programme to be submitted on or before such date as the Secretary of State may direct. The recipient of a Section 29 Notice must consult the OGA before submitting a decommissioning programme to the Secretary of State. The Petroleum Act requires the OGA to consider alternatives to decommissioning (such as reuse of the relevant installation), and to consider how to keep the cost of the programme to a minimum. Once the decommissioning programme is approved by the Secretary of State, the Section 29 notice holders are legally obliged to carry out the decommissioning programme on a joint and several liability basis. If they fail to do so, the Secretary of State may step in to carry out the work and invoice the Section 29 Notice holders.

In theory, the Secretary of State can serve a Section 29 Notice on a wide range of parties; not just the present licensees and operator but also anyone owning an 'interest' (which term is undefined in the Petroleum Act and therefore must be broadly construed) in an installation 'otherwise than as security for a loan' and associated companies (broadly 50 per cent, direct or indirect affiliates) of companies which are directly liable to have a Section 29 Notice served on them. The Secretary of State also has the power to withdraw Section 29 Notices (under Section 31(5)), for example, in respect of ex-licensees who have sold on their interest, but this is usually subject to the Secretary of State serving a Section 29 Notice on any incoming licensee and consulting other existing licensees. Crucially BEIS can reissue any notices withdrawn in this way (under Section 34) so the risk of (re)incurring liability for former licensees is never extinguished.

BEIS publishes guidance notes on the decommissioning of offshore installations and pipelines. BEIS released a revised version of the guidance notes in May 2018 (the Guidance Notes), providing further clarity and detail around decommissioning processes and the contents of a decommissioning programme. The decommissioning programme will set out and describe in detail the proposed measures to be taken and will include estimated costs, an inventory of materials including radioactive material, environmental impact assessment, a summary of the methods to be used to plug and abandon wells, a description of relevant installations, pipelines and materials on the seabed, removal of debris from the seabed and ongoing monitoring of the area after removal of the installation. The decommissioning programme will also tie in with related consents procedures under other applicable law. There are a number of possibilities for the items being decommissioned, including salvage, waste storage, carbon capture and storage, pipeline reuse and recycling. At the time of writing, section 12 of the Guidance Notes (on environmental considerations for decommissioning) had only been released in draft form.

The Secretary of State can ask for decommissioning security at any time with such security being ring fenced from creditors in an insolvency situation. The Guidance Notes state that OPRED has developed a financial policy, to be released in 2018, which will include the circumstances in which decommissioning security may be appropriate.

The increasing emergence of decommissioning security arrangements, as part of a sale and purchase agreement, resulted in the development of the Oil and Gas UK Decommissioning Security Agreement, which is now commonly entered into by all licensees. The agreements primary aims are to mitigate the risk of a party incurring 'double security', to allow a uniform approach to what is acceptable security (how much is required and when) and to reduce negotiation costs and lost management time. The agreement provides for decommissioning security to be held on trust by an independent security trustee. Decommissioning security may be put into the trust by way of cash (rare in practice), standby letter of credit, performance bond or insurance product. Annexure E of the Guidance Notes contains commentary on the minimum requirements for a decommissioning security agreement where the Secretary of State is to be a party. The commentary emphasises that security must be irrevocable, available on demand and issued by a UK body of substance. Parent company guarantees are not considered acceptable security, because (among other reasons) it could be argued that guarantees are not primary contractual obligations, resulting in litigation that could delay timely decommissioning.

OPRED is currently reviewing the decommissioning security agreement template, in light of recent low oil prices and new operators in the UKCS, so existing policy and guidance may change in the coming year. As noted above, OPRED is also due to publish a financial policy in 2018, which will focus on ensuring adequate funding and security are available for decommissioning costs on a field-by-field basis.

Tax is critical to the amount of decommissioning security that is required. Under the UK tax regime, a signification portion of decommissioning costs can be reclaimed, when such costs are incurred, as a tax deduction in relation to RFCT, SC and PRT, where applicable (see further commentary at Section VIII). There have historically been frequent and unsettling changes to the UK tax regime, which created a fear among licensees, that when the total tax relief exceeded tax revenues, the government would once again change the rules. Decommissioning security agreements therefore required that security be posted on a gross basis, ignoring any tax relief. In 2013, in order to encourage investment, the government introduced the Decommissioning Relief Deed. The Decommissioning Relief Deed is a contract entered into by the government and individual companies under which the government protects the licensee from the following change in law: if the law changes after the enactment of the Finance Act 2013, such that the total tax relief achieved by the licensee is less than the amount of relief that would have been available had the law not changed, then the government will make a tax-free payment of the difference to the licensee.


i Growth of decommissioning

One of the features of a mature basin is the fact that a large number of fields are near the end of their operational life. The decommissioning of smaller rigs has been under way for years as production began to decline, but a new wave of bigger projects is due to be decommissioned. The recent report by the OGA 'UKCS Decommissioning 2018 Cost Estimate Report' estimated the P50 cost of decommissioning at £55.7 billion in 2016 prices. Not all of this cost will be borne by the industry: through the tax relief mechanism the UK tax payer will incur more than half the cost of decommissioning. OGA has stated that its goal is to reduce its P50 cost estimate by 35 per cent from the 2017 estimate of £59.7 billion down to £39 billion. There are many ideas in the mix – the use of collaborative initiatives such as multi-operator well plugging and abandonment campaigns and sharing information among operators to create a more capable decommissioning supply chain. The government is also trying to bring new players into the game by allowing the tax relief for decommissioning to be attached to the asset rather than the licensee as it currently is (see below).

ii Transferable tax history and PRT post-transfer decommissioning expenditure

In March 2017, the government published a discussion paper titled 'Tax issues for late-life oil and gas assets'. The paper identified two areas of the UK fiscal regime that may be preventing transactions involving late-life oil and gas assets. Both of these areas are now the subject of draft legislation, published for consultation on 6 July 2018. The proposed changes aim to extend the productive lives of late-life oil and gas fields, which should lead to delayed decommissioning and support increased investment in the UKCS. Both measures are to apply to the transfer of licence interests receiving OGA approval on or after 1 November 2018. The legislation is due to be finalised as part of the Finance Act 2018–19.

Transferable tax history (TTH)

Under the current regime, a licensee can offset some of its decommissioning expenditure against previous taxable profits. However, tax history attaches to the licensee who paid the tax, and cannot be transferred to an incoming licensee. As a result, the buyer of an interest in a mature licence may not be able to generate enough tax history to access tax relief at the time of decommissioning. The draft legislation addresses this issue by including a mechanism allowing the buyer and seller of a licence interest to make a joint election to transfer a portion of the seller's profits subject to RFCT and SC (together, the TTH) to the buyer. The draft legislation includes complex provisions around the amount of TTH that can be transferred, when the TTH will be 'activated' (when (1) production has permanently ceased; and (2) the buyer's total decommissioning expenditure exceeds the total net profits accrued by the buyer) and ongoing requirements of the buyer to track the total net profits of the acquired interest.

PRT post-transfer decommissioning expenditure

It is common for sellers to retain liability for decommissioning under an agreement for the sale and purchase of a licence. Under the current regime, if the seller does not retain an interest in the licence, neither the seller or the buyer can claim a PRT deduction for decommissioning expenditure incurred by the seller or subsidised by the seller. This is because: (1) the seller can no longer lodge a PRT return as a 'participator' under the Oil Taxation Act 1975; and (2) the buyer cannot claim costs reimbursed by the seller because of restrictions on subsidised expenditure (which is disregarded for PRT purposes under Paragraph 8 of Schedule 3 to the Oil Taxation Act 1975 (the Anti-Subsidy Rule). This situation results in the need for complex and uncommercial arrangements for buyers to access tax relief. The draft legislation addresses this issue by: (1) treating expenditure incurred by the seller as having been incurred by the buyer; (2) treating expenditure subsidised by the seller as having been incurred by the buyer; and (3) disregarding the Anti-Subsidy Rule in both cases.

iii The UK's decision to exit the European Union (Brexit)

In general terms Brexit has made the allocation of capital in the UK a more difficult process than it already was, by creating a level of uncertainty in financial markets. This is equally applicable to the UK petroleum industry and its regulation, but there remains some uncertainty as to whether there will be a material impact in practice. The industry body Oil and Gas UK has listed a number of potential barriers to trade that may impact on the UK petroleum industry following Brexit, including increased tariffs, reduced mobility of labour, customs delays and additional regulatory burden. Other industry commentators suggest Brexit will have a more limited effect on the petroleum industry and this will, therefore, be a key area to watch in the coming years.


1 Jason Lovell is a partner, Jubilee Easo is a legal director, and Chris Pass is an associate in the oil and gas team of Eversheds Sutherland (International) LLP, based in London.

2 Oil and Gas UK Economic Report 2018.

3 Oil and Gas UK Business Outlook 2018.

4 Oil and Gas UK Business Outlook 2018.

5 The Oil and Gas Authority (Offshore Petroleum)(Retention of Information and Samples) Regulations 2018 came into force in May 2018, placing obligations on relevant persons (including licensees, owners of upstream infrastructure and owners of offshore installations) to retain petroleum related information and samples, in most cases until they are provided to the OGA under Section 34 of the Energy Act 2016. The Oil and Gas Authority (Offshore Petroleum)(Disclosure of Protected Material After Specified Period) Regulations 2018 came into force in August 2018, and state when the OGA may publish information obtained under the Energy Act 2016. The time periods for disclosure have been linked to the nature of the relevant information or sample, taking account of the factors listed in Section 66 of the Energy Act 2016 (such as the risk of discouraging the acquisition of information or samples).

6 Onshore certain functions and powers of the OGA related to onshore petroleum licencing in Scotland and Wales have been devolved to Scottish Ministers and Welsh Ministers (see further below).

7 The Scotland Act 2016, the Wales Act 2017 and associated statutory instruments have seen responsibility for onshore petroleum licensing in Scotland and Wales transferred from the OGA to (respectively) Scottish Ministers and Welsh Ministers. The practical impact of this devolution of powers remains to be seen and will be an area of interest in the years ahead.

8 Piper Alpha was a large North Sea oil and gas platform that started production in 1976. In July 1988 there was a leak of gas condensate that caused a massive explosion, leading to the death of 167 people.

9 Lord Cullen chaired the official public inquiry into the Piper Alpha disaster and made 106 recommendations within his report, all of which were accepted by the government.