The oil and gas industry in the UK is in a period of transition – adapting to a changing energy landscape, driven by the need to move towards a lower carbon economy, and evolving to address the realities of the UK continental shelf (UKCS) as a mature and complex basin. These driving factors have shaped trends in the UK oil and gas industry's transactional and operating landscapes over recent years, as well as informing a number of recent legislative developments – in particular relating to innovation, decommissioning and 'decarbonisation' initiatives.

The UKCS still represents a significant resource in terms of both current production and future potential. It has the largest production capacity in the EU, and the second largest in the EEA after Norway. Although production trends are forecast to return to a position of decline in the early 2020s, there are still areas of significant growth potential within the basin, primarily west of Shetland, an area characterised by challenging conditions and limited existing infrastructure.2 In implementing its formal 'maximising economic recovery' (MER UK) strategy, described in more detail below, the UK Oil & Gas Authority (OGA) has encouraged an approach of 'right assets, right hands' – ensuring that assets (as investment opportunities) are in the most appropriate hands as a key enabler in the drive to maximise economic recovery. While pursuing the MER UK strategy, the OGA supports the transition to a low carbon economy, and works collaboratively with industry, government and others to harness the necessary expertise, skills and infrastructure of the UK oil and gas sector to help achieve it. The oil and gas industry has a vital role to play in this transition and will continue to provide the majority of energy needs, both in the UK and globally, for at least the medium term.3

While deal activity during 2018 did not quite reach the levels seen in 2017, there were a number of significant M&A transactions within the UKCS in 2018 year and moving towards an increase within the first half of 2019. Total M&A spend for 2018 reached approximately US$5.6 billion, with 22 assets changing hands.4 M&A spend for upstream deals announced in the first half of 2019 alone has reached over US$4.5 billion.5 A variety of transactions occurred across all stages of the upstream oil and gas life cycle, including exploration prospects, pre-development opportunities, producing fields and late-life assets. 'Right assets, right hands' – having investment opportunities in the most appropriate hands, is a key enabler in the drive to maximise economic recovery. Recent transactions have resulted in a more diverse corporate landscape on the UKCS, with the largest 10 companies accounting for just over half of production in 2018, compared with more than two-thirds of production in 2008.6 A significant trend continuing to develop during 2018 and into 2019 is the increasing proportion of UK assets, production and investment opportunities that are owned by private equity-backed companies. A number of these companies over the past two years have increased their exposure to the UKCS across various asset classes including the whole upstream life cycle, and particularly in the midstream sector. Private equity funds are generally able to view investment opportunities with a different focus to previous 'traditional' owners, given their different investment time horizons and freedom from immediate market pressures, and are able to adopt a flexible and efficient approach to maximise the value of their operations and investments.

The UKCS basin retains significant resources and a continued focus on exploration and development of new fields. Many exciting prospects continue to be developed, and production has been on the upswing. Nine new Field Development Plans were approved by the OGA in 2018.7 Total production from the UKCS was around 619 million boe in 2018, or 1.7 million boe per day, representing a total 20 per cent increase over the past five years. The OGA's estimate for proven and probable8 UK reserves as at the end of 2018 is 5.5 billion boe, slightly higher than as at the end of 2017 despite a year's production. The UKCS still retains over 10 to 20 billion barrels yet to be produced.9 On the basis of current production projections, this could sustain production from the UKCS for another 20 years or more.


The principal legislation governing oil and gas exploration and production of crude oil, gas and shale gas in the UK is the Petroleum Act 1998 (as amended) (the Petroleum Act). The Petroleum Act governs all oil and gas exploration and production in the UK (other than onshore in Northern Ireland), and underpins a regime whereby licences are granted, by the OGA (and by the Welsh Ministers, for onshore oil and gas in Wales, and the Scottish Ministers, for onshore oil and gas in Scotland), to persons to 'search and bore for and get' petroleum. Licence holders are granted the right to explore and develop a specified geographical area. Ownership of petroleum vests in the Crown, and petroleum produced within the licence area transfers from the Crown to the licence holder at the well head. The licensing regime, and the rights and obligations of the licence holder, are set out in more detail in Section III.

The Petroleum Act is supplemented by the Energy Act 2016, the Infrastructure Act 2015 and various environmental and health and safety legislative provisions (set out in more detail in Section VII).

The Department for Business Energy and Industrial Strategy (BEIS) is responsible for setting energy and climate change mitigation policies, and establishing the framework for achieving the policy goals in those areas.

From 1 October 2016, pursuant to the Energy Act 2016, the OGA was formally established as a fully independent regulator and a government-owned company, with the Secretary of State for Business, Energy and Industrial Strategy (the Secretary of State) as the sole shareholder. The Secretary of State is ultimately responsible to Parliament for the OGA.

The OGA is the entity responsible for petroleum licensing and regulation of the upstream oil and gas sector, including:

  1. oil and gas licensing;
  2. oil and gas exploration and production;
  3. oil and gas fields and wells;
  4. oil and gas infrastructure; and
  5. carbon storage licensing.

In response to the decline in production from the UKCS, the UK government commissioned a review of the UK offshore oil and gas recovery and regulation led by Sir Ian Wood. The concluding recommendations of this review made various recommendations, including the establishment of a new regulator (the OGA, as noted above). The key principle of the recommendations, and the stated policy of the UK government, is to maximise the cost-effective recovery of UK resources (MER UK). The Infrastructure Act 2015 amended the Petroleum Act, to implement an official MER UK strategy, which was produced by the Secretary of State and came into force in March 2016. The MER UK strategy is binding on the OGA, various industry participants, the Secretary of State and licence holders, operators and owners of offshore installations. The OGA has enforcement powers in respect of compliance with MER UK, and it is required to act in accordance with its MER UK strategy when:

  1. exercising its functions under the Petroleum Act or part 2 of the Energy Act 2016;
  2. exercising functions or powers under a petroleum licence; and
  3. using its ancillary powers, for example, to assist or advise the government.


The Petroleum Act vests all rights to petroleum in the Crown but permits the OGA to grant licences to 'search and bore for and get' petroleum to persons deemed fit. Under the Petroleum Act, exploration for and production of petroleum in the UK and on the UKCS can only be undertaken under the terms of these licences. A company wishing to participate in the UK upstream oil and gas sector must bid for a licence or acquire an interest in existing assets, with any acquisition being subject to regulatory consents.

The OGA is now responsible for issuing licences through competitive licensing rounds that generally take place every year, and the MER UK strategy is applied by the OGA in each licensing round. Separate rounds are held for seaward (offshore) licences and landward (onshore) licences. In exceptional circumstances, where there are compelling reasons, the OGA may issue a licence outside of a licensing round. The OGA can only accept licence applications in response to a formal invitation to apply for a licence, so a company seeking an out-of-round licence must make a case to the OGA that out-of-round applications are justified.

Licences take the form of a deed, pursuant to which the licensee is bound to observe the conditions of the licence. These detailed terms and conditions are prescribed in a series of 'Model Clauses', which are set out in secondary legislation under the Petroleum Act. The model clauses applicable to a particular licence are those that are in force at the time the licence was granted, and are not affected by subsequent sets of model clauses, except through specifically retrospective measures.

UK licences are both contractual and regulatory in nature – contractually, being executed as a deed and providing for the contractual transfer of rights from the Crown to the licensee, and regulatory, because the model clauses are encompassed in statutory regulations, and Parliament may unilaterally amend the terms upon which a licence is granted. Legally, only one licence exists, although a licence may be granted to one or more licensees, who will be held jointly and severally liable in respect of obligations arising under the licence.

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. The OGA will only grant a licence to an entity that has the appropriate technical and financial capacity to contribute to the MER UK strategy. The OGA considers all applications on an individual basis, and companies must meet certain criteria, including technical competence, financial capacity and tax considerations (the OGA routinely corresponds with HMRC for information on any tax issues). Prospective licensees must also satisfy the OGA that they have a place of business in the UK, meaning they must have either a staffed presence in the UK, be a UK company or have a UK branch of a foreign company.

The different types of licences currently being issued are:

  1. seaward production licences: These are the main offshore production licence, which run for three successive periods or terms. The initial term is associated with exploration, the second with development and the third with production. However, the licence requires fulfilment of the relevant work programme, agreed with the OGA, before it can proceed from one term to the next – but a licensee who fulfils the required obligations and obtains the relevant consents quickly during the initial terms, will not be prevented from commencing production under the licence prior to the third term. Production licences expire automatically at the end of the term unless the licensee has advanced the work programme sufficiently to commence the next term. The licence will expire at the end of its initial term unless varied by agreement, or the licensee has completed the work programme, all sums have been paid, and the licensee has relinquished 50 per cent of the initial licence area. Each production licence also requires payment of an annual fee (known as rental), charged on an escalating basis for each square kilometre covered by the licence at that date, licensees to relinquish areas that are not being exploited;
  2. landward production licences: The onshore equivalent of seaward production licences as described above (and formerly referred to as petroleum exploration and development licences);
  3. offshore innovate licences: The innovate licence offers greater flexibility during the initial and second term and an applicant for an 'innovate' licence can propose the durations of the initial and second terms. The 'offshore innovate licence' replaced the traditional, promote and frontier versions of the seaward production licence, described below (which still remain relevant for many existing offshore production licences); and
  4. exploration licences: An exploration licence is non-exclusive and covers the UK's entire offshore area apart from those areas covered by any production licences that are in force at the time: These are commonly used by seismic contractors who gather data to sell rather than exploiting the resources themselves, or by holders of a production licence who wish to explore outside the areas where they hold or require exclusive rights. The OGA grants both seaward (offshore) and landward (onshore) exploration licences. The annual payment is significantly lower than that of production licences and covers exploration relating to hydrocarbon production, gas storage, carbon capture and sequestration or any combination. An exploration licence grants rights to explore for petroleum, but not to extract it. It enables licence holders to carry out seismic surveys and to drill wells for core-sampling to a maximum depth of 350 metres below the seabed.

The 'traditional, promote and frontier licences' are no longer issued, but many remain in existence:

  1. traditional licence. This was the most common type of offshore production licence. They were granted with licence term lengths of four years for the initial term to complete the initial work programme, following which the licensee was required to relinquish 50 per cent of its acreage to move to the next phase. The second term was for another four years, and finally reaching a production phase for an 18 year third term (other than in relation to the 27th and 28th licensing rounds where greater flexibility was introduced for certain licences);
  2. promote licence. This licence was aimed at small and start-up companies. Applicants did not need to prove technical or environmental competence or financial capability before the award of the licence, but they were required to do so within two years of the start date of the licence. Otherwise, the terms of the various phases and relinquishment obligations were the same as a traditional licence
  3. frontier licence. This licence had an exploration phase of six years to allow companies to evaluate larger areas and look for a wider range of prospects, but the terms varied based on the terrain (two more years for standard frontier licences and five additional years for the more challenging West of Shetland frontier licences). Licensees are required 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 at the end of the initial exploration phase.

On 11 July 2019, the 32nd UK Offshore Licensing Round officially opened, inviting applications for licences up to 12 November 2019.

A total of 796 blocks or part-blocks on offer across the main producing areas of the UKCS with acreage are on offer in the Central North Sea, Northern North Sea, Southern North Sea and the West of Shetlands.


There is no national oil company in the UK that is directly involved in oil and gas exploration and production activities in the UKCS. Oil and gas exploration and production are regulated by restrictions on the award and transfer of licences, and requirements relating to approval of work programmes and how that work is performed. There are no special regulatory requirements that apply to the exports of oil or oil products, other than the payment of applicable duties or taxes, and compliance with EU oil stocking obligations. In the event of an actual or threatened emergency in the UK that will affect fuel supplies, the Secretary of State may use emergency powers under the Energy Act 2016 to regulate or prohibit the production, supply, acquisition or use of substances used as fuel.


The OGA's consent is required for a licence to be sold, transferred, assigned or otherwise dealt. Any transaction that results in a company joining a licence, or withdrawing from a licence, is deemed to be a licence assignment. The OGA will consider any assignment made without prior consent, a very serious breach of the model clauses and grounds for immediate revocation of the licence or to reverse the assignment. There are a number of issues that the OGA considers when deciding whether to give approval, including: compliance with the EU 2013 Offshore Safety Directive, the technical and financial capacity of the assignee, decommissioning costs, effect on operatorship arrangements and fragmentation of licence interests (i.e., creation of less than 5 percent interests).

The company selling its licence interest (the transferor) must apply to the OGA for its consent. The transferor will need to obtain much of the information the OGA needs from the acquiring company (the transferee). Consent will not be granted unless the OGA has all required information. The OGA reviews and considers the form of the deed of assignment used by the parties, and provides for approved draft deeds of assignment. Licence assignment applications are processed online through the UK Energy Portal, and the OGA aims to process applications within 10 working days. If the assignment results in a change of operatorship, this may extend the process to as long as 30 working days. Assignment consents are valid for 90 days after the completion date specified in the application form.

While the model clauses or other applicable legislation do not expressly require the OGA's consent to proceed with a change of control of a licensee, the OGA does have the power to require either a further change of control, or revocation of the licence, upon a change of control. As a result, best practice is to apply to the OGA in advance of a change of control, and seek comfort that the OGA will not exercise its powers. The application should demonstrate that the proposed change of control would not impact the ability of the licence holder to meet its obligations under the licence. The OGA may require a parent company guarantee from the new corporate parent to replace any existing parent company guarantee that may have been issued before the change in control.

The creation of a charge on a licence also requires the consent of the OGA. To facilitate ordinary course transaction financing, and to eliminate the cumbersome need for prior consent, 'open permission', which is a form of automatic consent, applies to any fixed or floating charge or debenture. The licensee must give notice to the OGA within 10 days of creation of the charge, providing certain information about the charge. If the holder of a charge intends to enforce the security interest, it will be caught as a licence assignment, and the procedures described above in respect of licence assignments will apply.


The tax system applicable to oil and gas related activities in the UK (and the UKCS) consists of a special fiscal regime, comprising three principal elements:

  1. ring fence corporation tax (RFCT): The normal corporation tax regime is modified in its application to companies producing oil in the UK and UKCS: a 'ring fence' applies to prevent taxable profits from oil and gas extraction from being reduced by losses from other activities. The rate of RFCT is currently 30 per cent. Despite the recent and prospective cuts in the main rate of corporation tax, the rate will remain at 30 per cent for profits from oil extraction in the UK and the UKCS;
  2. supplementary charge (SC): This is 10 per cent with effect from 1 January 2016 (previously 20 per cent). This is not strictly corporation tax, but is charged as if it were an amount of corporation tax on ring fence profits to which financing costs are added back (and is subject to an allowance regime designed to encourage investment); and
  3. petroleum revenue tax (PRT): This is an additional level of tax on the profits derived from particular fields. The rate of PRT was reduced to zero with respect to chargeable periods ending after 31 December 2015 but it has not been abolished so losses can be carried back against past PRT payments.

Following the effective abolition of PRT, RFCT and SC together result in an effective marginal tax rate of 40 per cent for all oil and gas fields in the North Sea.

Investment in the UKCS is encouraged by tax relief being provided for expenditure on research, exploration, appraisal and production, either through capital allowances (broadly, the UK's form of allowable 'tax' depreciation) and also, once production has commenced, through tax deductions for expenses incurred wholly and exclusively for the purposes of an eligible trade. The government has also signed decommissioning relief deeds with oil and gas companies to provide certainty on the tax relief they will receive when decommissioning assets, as further described below.

In the context of UKCS transactions, decommissioning issues, and particularly the question of with whom the economic burden of decommissioning liabilities should lie, have frequently been a significant challenge to transactions involving the transfer of UKCS licence interests. The traditional position has been that buyers would provide sellers with an indemnity for all decommissioning liabilities whether they arise on or before the agreed economic date or date of the agreement.

There has been, however, an increasing trend toward sellers of licence interests retaining a proportion of the decommissioning liability (as historically, it was likely that the new owners would not be able to get effective tax relief for decommissioning costs, due to having paid insufficient amounts of corporation tax and SC by the time the decommissioning of those assets occurred). This has been particularly relevant in the context of late-life assets where a seller is likely to have significantly greater tax capacity than a buyer. However, in the context of 'right assets, right hands' and the MER UK strategy, following an announcement in the Autumn 2017 Budget, the Finance Act 2019 introduced transferable tax histories (TTHs) for oil and gas companies, which provide companies buying North Sea oil and gas fields with certainty that they will get tax relief for the decommissioning of the asset as, on purchasing the asset, they will be able to make a joint election for the buyer to acquire some of the previous owner's tax history (namely historic profits on which ring-fenced corporation tax and supplementary charge have been paid). The buyer will then be able to set the costs of decommissioning the fields at the end of their lives against the TTH. The measure applies to licence transfers that receive OGA approval on or after 1 November 2018.

The recent amendments enacted are beneficial for a number of UKCS participants including:

  1. taxpayers selling licence interests who may be able to dispose of UKCS assets and thereby unlock capital to be employed in further exploration and development activity (whether in the UK or elsewhere) if a transaction can be structured such that the seller's TTH is transferred to the buyer; and
  2. buyers of such assets who may have greater certainty that tax relief will be obtained for the cost of decommissioning activity.


i Environmental impact and safety

While oil and gas exploration, development and production is primarily regulated by the licence and the Petroleum Act, various other statutory provisions apply in respect of environmental issues. The Model Clauses also generally require licensees to operate in accordance with 'good oilfield practice' and to take all steps practicable in order to prevent the escape or waste of petroleum, including into any waters in or near the vicinity of the licensed area.

The principal regulators for HSE in the UKCS are BEIS, the Health and Safety Executive, and a partnership between the two – the Offshore Safety Directive Regulator (OSDR), established in 2014 pursuant to the European Commission Offshore Safety Directive (2013/30/EU) (the 2013 Directive), which itself was a direct response to the Deepwater Horizon disaster in 2010. The European Commission is currently assessing whether the 2013 Directive, applicable in the UK, has achieved its objective of ensuring safe offshore oil and gas operations, pursuant to an evaluation planned to be completed and released in the third quarter of 2019.

Following the Piper Alpha offshore platform explosion in 1988, and the subsequent Cullen Inquiry, the UK developed the Offshore Installations (Safety Case) Regulations 2005 (followed by the Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015), which impose obligations on the operator to prepare safety cases and risk assessments to be approved by the Health and Safety Executive for all offshore installations.

The OGA has the power to issue financial penalty notices carrying fines of up to £1 million under the Energy Act 2016, in respect of: (1) a failure to act in accordance with the MER UK strategy; (2) a breach of a condition of an offshore licence, or (3) other breaches of the Energy Act 2016 that are sanctionable thereunder. It may also order the removal of the operator of a licence and ultimately revoke a licence for one or all of the licence holders in the event of non-compliance with applicable requirements.

The Offshore Petroleum Regulator for Environment & Decommissioning (OPRED), an agency of BEIS, is principally responsible for enforcing the environmental regime applicable to offshore oil and gas activities (and also decommissioning) in the UK. The UK government has recently enacted the Offshore Environmental Civil Sanctions Regulations 2018 (the OECS Regulations) to allow OPRED to impose civil sanctions in respect of breaches of some existing offshore oil and gas environmental regulations. Previously, the breaches could only be sanctioned through criminal prosecution. As noted in the UK government's January 2018 consultation in relation to the proposals, while criminal prosecutions can result in substantial financial penalties being imposed by the criminal courts, this process is 'slow, resource intensive and costly'. The UK government considers that the new civil sanctions will provide OPRED with 'a more flexible, proportionate and timely enforcement response in respect of breaches that amount to criminal offences'. It is relevant to note that the new civil sanctions will only apply to breaches that can currently be subject to criminal prosecution, and as such, the OECS Regulations do not create any new offences – only an alternative means for OPRED to sanction these breaches. OPRED can impose a penalty in circumstances where it is satisfied that a breach has been proven beyond reasonable doubt (the criminal burden of proof).

These new civil penalties will apply to offences under the following regulations, being the key UK regulations relating to the offshore oil and gas industry:

  1. the Offshore Combustion Installations (Pollution Prevention and Control) Regulations 2013;
  2. the Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005;
  3. the Offshore Installations (Emergency Pollution Control) Regulations 2002;
  4. the Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998; and
  5. the Offshore Chemicals Regulations 2002.

In the event of an oil spill in UKCS 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 other torts such as nuisance and negligence. Otherwise, licensees suffering damage caused by operations of an offshore installation may claim under a voluntary oil pollution compensation agreement to which all offshore operators active in the UKCS are party. Membership of the offshore pollution liability agreement (OPOL), is a condition of OGA granting a licence and so all operators will in practice be party. OPOL subjects operators to strict liability for pollution damage, and the cost of remedial measures up to a maximum of US$250 million per incident.

ii Decommissioning

Oil and gas operators in the UK are increasingly decommissioning their assets as they are reaching the end of their useful economic lives. Operators' expenditure on decommissioning is rising: they have spent more than £1 billion on decommissioning in each year since 2014.10

The Petroleum Act imposes an obligation on licensees to pay for the decommissioning and proper removal of offshore installations from the seabed, other than in exceptional circumstances. Decommissioning of these installations (including pipelines) is regulated by BEIS, through OPRED. The OGA, pursuant to MER UK and the Energy Act 2016, is required to assess decommissioning programmes to ensure they meet the MER UK principal objectives on the basis of cost savings, future alternative use and collaboration.

The Secretary of State, under Section 29 of the Petroleum Act, has the power to serve a 'Section 29 Notice' to anyone owning an 'interest' in an installation 'otherwise than as security for a loan' and associated companies (broadly 50 per cent owned direct or indirect affiliates) of companies that are directly liable. The Section 29 Notice will either specify the date by which a decommissioning programme for each installation or pipeline is to be submitted or, as is more usual, provide for it to be submitted on or before such date as the Secretary of State may direct. At first instance a Section 29 Notice would typically be issued to the operator of the field and each of the licensees, but the power of Secretary of State to issue a Section 29 Notice to other relevant parties is broad, and should be considered in transaction structures in an M&A context. It is expected that the OGA will send a Section 29 Notice to this wider class of parties if it finds the decommissioning arrangements proposed by the operator and licensees to be unsatisfactory.

The Secretary of State has the power to withdraw Section 29 Notices, for example, in respect of withdrawing licensees, but it would be unusual for this to occur without a replacement notice to be serviced on an incoming licensee. Additionally, BEIS has the power to reissue any Section 29 Notice (under Section 34 of the Petroleum Act) – it is important to note that the risk of a licensee (or other interested party or related person as set out above) re-incurring liability is always present, and they may be potentially liable for the decommissioning of that field until decommissioning is complete.

The Section 29 Notice requires the recipient to submit a decommissioning programme (setting out the methods and measures to decommission disused installations or pipelines, or both). Once the decommissioning programme is approved, following the OGA's review of the details including the cost estimates, the notice holders are legally obliged to carry it out on a joint and several liability basis. If a programme is not carried out or its conditions are not complied with, the Secretary of State may, by written notice, require remedial action to be taken. Failure to comply with any such notice is an offence, and the Secretary of State can carry out the remedial action and recover the costs from the person to whom the notice was given.

The Secretary of State can require decommissioning security at any time, with the security being ring-fenced from creditors in an insolvency situation, if it believes that there is an unacceptable level of risk of decommissioning costs falling to government. The industry and the regulators have developed the Oil and Gas UK Decommissioning Security Agreement, which is the form of security commonly entered into by all licensees, providing for security to be held on trust by an independent security trustee. This security may be provided by a standby letter of credit, performance bond or insurance product, or cash (but may not be a parent company guarantee).

To date, OPRED has agreed nine security agreements with operators, and a total of £844 million has been set aside for decommissioning.11 OPRED monitors the financial health of operators to determine their financial position compared with their anticipated costs to decommission assets. For example, it assesses operators' ratio of assets to liabilities in their accounts and has access to data provided by a consultancy firm on operators' financial health.

In response to concern that a lack of certainty about decommissioning tax relief had led operators to set aside money for decommissioning on a pre-tax (rather than post-tax) basis, in 2013, HM Treasury introduced decommissioning relief deeds to give operators greater certainty about the tax relief they will receive for decommissioning. These deeds guarantee that tax relief for decommissioning will not be lower than under 2013 rules and provide certainty that operators will receive tax relief should they incur any additional decommissioning costs due to the default of another party. The rationale is that this will reduce the amount of security required (before security was given without taking account of tax relief, therefore, increasing the amount), which will free up funds for asset transactions and investments, and discourage early decommissioning.


i UKCS in transition: decommissioning as part of the value chain

Both government and industry are facing the changing circumstance of the 'energy transition' – driven by economic, geological and political realities. As assets age and we push towards a lower carbon economy, increasingly government and industry are aligned and seeking to ensure that decommissioning is not (and is not seen as) solely a loss-making, mandatory action.

In the spring of 2019, the UK government completed a consultation on 'Strengthening the UK's offshore oil and gas decommissioning industry', focusing in large part on building on existing fiscal, policy and collaborative measures, how the UK decommissioning industry could further improve its ability to serve the UK market, support MER UK and reduce the overall costs of decommissioning. The TTH, introduced in 2018, as described above, allows companies selling UKCS interests to transfer tax payment history to the buyer. The buyer will then be able to set the costs of decommissioning the fields at the end of their lives against the TTH, incentivising bringing new investors (and new capital) into the arena who may not previously have been able to benefit.

A particularly exciting and innovative initiative on the legislative horizon that would also create value through decommissioning is the potential for the reuse of existing end-of-life oil and gas infrastructure for carbon capture usage and storage (CCUS) projects. The reuse of existing oil and gas infrastructure for CCUS could present a significant opportunity to reduce costs for initial projects. The UK government has committed to a 'CCUS Action Plan' including a commitment to deliver the UK's first CCUS project from the mid-2020s. A public consultation completed in the fall of 2019 sought input on:

  1. identification of existing oil and gas infrastructure that has the potential for reuse and to develop a policy to support the development of CCUS in the UK;
  2. whether government should introduce a discretionary power for the Secretary of State to remove the decommissioning liability from previous oil and gas asset owners if assets are transferred to CCUS projects; and
  3. changing guidance from the OGA and government to encourage owners and operators of oil and gas assets to propose a period of suspension prior to decommissioning in circumstances in which there is a reasonable prospect of the asset being acquired by a CCUS project.

ii Brexit

While from a regulatory perspective, it is not certain that Brexit would have a significant impact on the UK upstream oil and gas regulatory regime, as it is highly developed independently of EU law, the impact of Brexit would almost certainly be felt across the industry commercially and financially due to overall economic uncertainty. Depending on the terms of any potential Brexit, the industry could be exposed to additional tariffs and the restrictions on the import of goods and services.


1 Michael Burns is a partner and the global co-head of the Oil and Gas Group, and Caroline Durran is an associate in the oil and gas team of Ashurst LLP, based in London.

5 http://www.mergermarket.com [Mergermarket deal reporting].

8 Reserves that are not yet proven, but which are estimated to have a better than 50 per cent chance of being technically and commercially producible.