Oil and gas regulation in the UK: overview

A Q&A guide to oil and gas regulation in the UK.

The Q&A gives a high level overview of the domestic oil and gas sector, rights to oil and gas, health safety and the environment, sale and trade in oil and gas, tax and enforcement of regulation. It covers transfer of rights; transportation by pipeline; environmental impact assessments; decommissioning; waste regulations and proposals for reform.

To compare answers across multiple jurisdictions, visit the energy and natural resources Oil and gas regulation Country Q&A tool.

This Q&A is part of the global guide to energy and natural resources. For a full list of content visit www.practicallaw.com/energy-guide.


Domestic sector

1. What is the role of the domestic oil sector in your jurisdiction?

The UK's oil and gas industry makes a substantial contribution to the country's energy security and economy. However, the UK Continental Shelf (UKCS), a mature oil producing area, has been negatively affected by the drop in oil and gas prices in 2014 and 2015. This has led to an estimated 15% reduction in the workforce supported by the oil and gas industry. Despite this, in August 2015 Oil & Gas UK (the UK offshore oil and gas industry association) estimated that the UKCS supports around 375,000 jobs, many of which are highly skilled and well paid.

UKCS oil and gas production provided just over 50% of the UK's oil and gas demand in 2014. By February 2016, there were 204 offshore oil fields in production, and more than 43 billion barrels of oil equivalent (boe) had been recovered since first production from the UKCS in 1967. Exploration in the UKCS continues, and recently an additional 150 million boe were discovered, largely in the northern North Sea and the West Shetlands.

There are also a significant number of onshore fields in the UK, though onshore oil and gas production accounted for only 2% of the UK total production in 2014. Recent conventional oil onshore sites have not yet resulted in significant production (including at the Arreton site on the Isle of Wight and in the Weald Basin in South East England).

Domestic production

According to reports by the Department of Energy and Climate Change (DECC), 3.623 billion tonnes of oil had been produced by the end of 2014, with 1.060 billion tonnes of proven, probable and possible reserves remaining.

UKCS oil production has been falling since 1999 at an average rate of 8% per year. However, 2014 saw a smaller drop in production (1.8%) and data for 2015 shows a significant increase (13.4%). Despite this increase, revenues from oil production in the UK fell significantly in 2015, due to reduced oil prices worldwide, and 43% of the UKCS oil fields are estimated to operate at a loss in 2016. There is a significant risk that the closure of even a small number of oil fields due to the prevailing market conditions may have a knock-on effect on other smaller oil fields that rely on other fields' infrastructure, resulting in further closures.

Oil imports/exports market

The UK became a net importer of crude oil and petroleum products in 2006 for the first time since the 1980s. Although there have been small changes in trade since then, the UK has remained a net importer. Consumption of petroleum fell by 29% between 1970 and 2012.

According to DECC statistics, exports of crude oil and natural gas liquids (NGLs) increased by 6.6% in 2015, consistent with higher production, while imports of crude oil and NGLs decreased by 7.6% in 2015. Imports of petroleum products went up 10.3% compared with 2014, with exports relatively unchanged.

Domestic market structure

Oil and gas resources are privately owned with very few and limited exceptions in relation to petroleum storage facilities with mixed military and civil use.

Government policy objectives

The stated policy of the UK Government is to maximise the cost-effective recovery of UK resources. 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 UKCS Maximising Recovery Review Final Report was published in February 2014 (Wood Review). In July 2014, the government published its formal response to the Wood Review and set out its proposals for implementing the Wood Review's recommendations (see Question 28). The new oil and gas regulatory body, the Oil and Gas Authority (OGA), was established on 1 April 2015. An Energy Bill was introduced in the House of Lords on 9 July 2015, which makes provision for the transfer of the Secretary of State for Energy and Climate Change's regulatory powers on oil and gas to the OGA and further defines its role and powers (including new regulatory powers).

In March 2016 the strategy for maximising economic recovery in the UK (MER UK) came into force. The key principle of the strategy is that "all stakeholders should be obliged to maximise the expected net value of economically recoverable petroleum from relevant UK waters, not the volume expected to be produced." If a relevant party decides not to ensure maximum economic recovery, it must allow others to seek to maximise the value of economically recoverable petroleum from its licence or infrastructure, including by divesting itself of the licence or asset "to other financially and technically competent persons". Where an operator's returns are unsatisfactory, or it cannot raise suitable finance to proceed, and cannot divest itself of the asset, MER UK requires it to relinquish the related licences after a reasonable period of time. However, it remains to be seen how this strategy will operate in practice, particularly given the current market conditions.

The UK Government has also declared that shale gas has the potential to contribute to the UK's energy security and economy. So far, only one exploratory shale gas well has been fracked in the UK, as hydraulic fracturing remains a matter of controversy (see Question 4).

Current market trends

In January 2016, crude oil prices dropped to their lowest level in 12 years. Although there has been a modest price growth since then, the outlook for oil prices remains "lower for longer". According to Baker Hughes International Rig Count data, the number of active rigs in the UK nearly halved over the course of 2015. Nevertheless, the production of oil in 2015 was higher than expected and the OGA has revised its 2016 production projections upwards. While production is projected to increase in 2016, new investment in the UKCS is expected to be greatly reduced.

2. What is the role of the natural gas sector in your jurisdiction?

According to the UK Gas Generation Strategy 2012, gas plays a critical role in maintaining energy security, affordability and decreasing carbon emissions in the UK.

The share of gas in UK primary energy consumption had increased from 5% in 1970 to 47% in 2014. The share of gas in UK power generation increased to 30% in 2014. Gas is expected to play a key role in the future, as the UK is committed to moving away from coal for electricity generation.

The domestic gas production provided around 55% of the UK's gas demand in 2014. There are currently 120 offshore gas fields in production.

Domestic production

According to reports by the Department of Energy and Climate Change (DECC), 2,486 billion cubic meters (bcm) of gas have been produced, both onshore and offshore, with 594 bcm of proven, probable and possible reserves remaining as at the end of 2014.

Between 2000 and 2013 domestic natural gas production fell by an average of 8% per annum. However, in 2014 natural gas production increased by 0.2% compared to 2013, and provisional data for 2015 shows that domestic production has increased significantly (gross gas production increased by 7.8% compared to 2014). This growth is partly due to the start-up of new fields (Jasmine and Kew) and the limited maintenance activity in 2014 and 2015.

Shale gas exploration is ongoing and the UK Government awarded exploration licences for 159 onshore gas blocks covering around 6,000 square miles in England in 2015. About 75% of these licences relate to shale gas.

Natural gas imports/exports

The UK is a net importer of natural gas with net imports of gas in 2014 accounting for 45% of supply. The main sources of gas imports are:

  • Three pipelines connecting the UK to Norway.

  • A pipeline connecting the UK to The Netherlands.

  • Two liquefied natural gas (LNG) terminals, which opened in 2009, producing 25% of the imports.

Norway is the largest supplier of gas, accounting for about 61% of total gas imports in 2015.

Imports of natural gas rose by 2.6% in 2015 compared to 2014. LNG imports went up by more than 20% in 2015, with LNG imports accounting for 31% of total gas imports. Qatar currently accounts for 92% of all LNG imports into the UK.

In 2015, gas export volumes went up by 24% compared with 2014, according to provisional DECC figures, due to increased production with stable imports and demand.

Domestic market structures

Oil and gas resources are privately owned with very few and limited exceptions in relation to petroleum storage facilities with mixed military and civil use.

Government policy objectives

The UK Government is committed to phasing out power generation from coal by 2025. Building new gas-fired power stations is seen as a critical step on the way to a low carbon energy system.

Gas has been replacing coal both in primary production and energy generation since 1970. The share of gas in the UK's energy mix continues to grow. According to provisional data from DECC, gas use in UK power generation rose by 6.1% to 20.5 billion cubic metres (bcm) in 2015.

In 2012, the UK Government announced that gas-fuelled power generation will continue for at least 15 to 20 years while under the Large Combustion Plant Directive around 12 giga-watts of coal and oil-fired power generation capacity closed by the end of 2015. Additionally, under the Industrial Emission Directive, up to 18.5 giga-watts of coal and 18 giga-watts of early gas fuelled generating capacity will be closed by the end of 2023.

Current market trends

Unlike oil markets, gas markets are regional in their nature. Gas prices have continued to decline in 2015 but not as sharply as oil prices. However, gas supply competition is increasing, with US Gulf LNG now capable of being shipped to Europe as soon as the price conditions are favourable.

3. Are domestic energy requirements met by oil and gas production?

Oil requirements

The UK produces around 34% of the oil and natural gas liquids required by its domestic market and imports from Norway, Algeria and Nigeria (among others) meet the rest of the domestic market's requirements.

Natural gas requirements

The UK currently produces around 45% of the natural gas required by its domestic market. However, as the result of declining supplies from gas sources in the North Sea, it is estimated that by 2020 around 70% of the UK's gas will have to be imported. LNG importation plays an important role in increasing the security and diversity of energy supplies to the UK.

4. Are there specific government policies to encourage the exploration and production of unconventional gas or oil?

Unconventional hydrocarbon exploration and production is subject to the onshore licensing regime (see Question 8), although additional regulatory requirements and planning permissions apply. In particular, a detailed Statement of Environmental Awareness must be submitted with the licence applications.

On 26 January 2015, the Environmental Audit Committee published its report on the Environmental Risks of Fracking and proposed an outright ban on fracking in the United Kingdom. The proposed ban on fracking was rejected. Instead, the Infrastructure Act 2015 (which came into force on 12 February 2015) places a number of restrictions on fracking. These include:

  • The requirement that the level of methane in groundwater be monitored for a period of 12 months before the start of fracking operations.

  • A bar from fracking:

    • "within protected groundwater source areas" (designed to protect domestic or food production water supplies); and

    • "within other protected areas" (designed to protect National Parks, the Norfolk and Suffolk Broads, other defined "areas of outstanding natural beauty", and World Heritage sites).

The Finance Bill 2014 introduced a new onshore allowance that removes a proportion of a company's profits from the Supplementary Charge (with effect from 5 December 2013)(see Question 10). This allowance applies to both conventional and unconventional projects, including shale gas, and replaces all existing field allowances for onshore projects.



Regulatory bodies

5. Who regulates the extraction of oil and gas?

The Department of Energy and Climate Change (DECC) is responsible for setting energy and climate change mitigation policies, and establishing the framework for achieving the policy goals in those areas.

From 1 April 2015, the Oil and Gas Authority (OGA) replaced the DECC as the entity responsible for petroleum licensing and regulation of the upstream oil and gas sector, including:

  • Decommissioning of offshore oil and gas installations and pipelines.

  • Enforcing environmental legislation as it applies to upstream oil and gas activities.

The Secretary of State for Energy and Climate Change (Secretary of State) is responsible for exercising many of the powers under the Petroleum Act 1998 and related legislation. A number of these powers will be transferred to the OGA by the Energy Act upon it coming into force, this is expected to take place in the first half of 2016.

DECC established the Office of Unconventional Gas and Oil to promote the safe, responsible and environmentally sound recovery of the UK's unconventional reserves of gas and oil.

The Environment Agency is the environmental regulator for all onshore oil and gas operations, including:

  • Shale gas.

  • Coal bed methane.

  • Underground coal gasification in England.

In April 2013, Natural Resources Wales, a new body formed by the Welsh Government, took over the functions previously carried out by the Environment Agency in Wales.

The Health and Safety Executive (HSE) is responsible for enforcing health and safety laws. In particular, the HSE's Energy Division regulates the risks to health and safety arising from work activity in the offshore oil and gas industry on the UK Continental Shelf (UKCS). The HSE also has an important role to play in regulating safety in other segments of the oil and gas industry (for example, oil and gas pipelines).

Ofgem is responsible for regulating the downstream gas market, and in particular the monopoly gas transmission and distribution networks. Ofgem also plays a role in enforcing the third party access regime that applies to downstream gas infrastructure.

See box, The regulatory authorities.


See box, The regulatory authorities.

Natural gas

See box, The regulatory authorities.


The regulatory regime

6. What is the regulatory regime for onshore and offshore oil and gas exploration and production?

The Petroleum Act 1998 (the Petroleum Act) establishes the regulatory regime applying to oil and gas exploration and production in the UK (other than onshore in Northern Ireland). The Petroleum Act vests all rights to petroleum in the Crown but permits the Secretary of State to grant licences to search and bore for and get petroleum to such persons as he thinks fit. The Petroleum Act is supplemented by various environmental and health and safety legislative provisions. All regulatory powers for the oil and gas industry, apart from those concerned with the environment, have been transferred from the Secretary of State to the Oil and Gas Authority.


Rights to oil and gas


7. How are rights to oil and gas held?

Under the Petroleum Act 1998, exploration for and production of petroleum in the UK and on the UKCS can only be undertaken under the terms of licences issued by the Secretary of State. A separate regime applies to onshore oil and gas in Northern Ireland, established under the powers devolved to the Northern Ireland Assembly.

The Department of Energy and Climate Change (DECC) previously issued licences through competitive licensing rounds that generally take place every year (see Question 7). This power has now been transferred to the Oil and Gas Authority (OGA). 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 such acquisition being subject to regulatory consents (see Question 9).

There are three main types of licences:

  • Seaward Production Licences. These are granted in relation to offshore fields. They cover the full life of a field, from exploration to production. There are some different sub-categories of Seaward Production Licences (see below).

  • Petroleum Exploration and Development Licences (PEDLs). These are granted in relation to onshore fields. These also cover the full life of a field.

  • Seaward Exploration Licences. These cover offshore exploration activities only. This type of licence is particularly aimed at seismic contractors who wish to gather data to sell rather than exploit geological resources themselves. The cost of the licence is a flat rate of GB£2,000 per year and covers non-intrusive exploration. The rights granted under an Exploration Licence are non-exclusive.

Seaward Production Licences and PEDLs are valid for a sequence of terms, designed to cover the typical life cycle of a field of exploration, appraisal and production. Each licence expires automatically at the end of each term, unless the licensee has sufficiently progressed to warrant a chance to move into the next term.

DECC has recognised that a standard Seaward Production Licence, often referred to as a "Traditional Licence", may not be appropriate in all cases. For this reason, the OGA also issues the following special types of Seaward Production Licences:

  • Promote Licence. This licence is aimed at small and start-up companies. Applicants do not need to prove technical/environmental competence or financial capability before the award of the licence, but they must do so within two years of the start date of the licence.

  • Frontier Licence. This licence has an exploration phase of six years to allow companies to evaluate larger areas and look for a wider range of prospects.

  • West of Shetland Frontier Licence. This is a variation of the Frontier Licence, specifically targeted at blocks located west of Shetland, with a longer exploration period of nine years.

The detailed terms and conditions of every licence are prescribed in a series of Model Clauses, which are set out in secondary legislation made 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. Model Clauses are not affected by subsequent sets of Model Clauses, except through specifically retrospective measures. From the twentieth licensing round onwards, the Model Clauses applicable to a particular licence have been set out in full in the licence to ensure clarity.


Nature of oil and gas rights

8. What are the key features of the leases, licences or concessions which are issued under the regulatory regime?

The objective of the regulatory regime is to:

  • Maximise recovery of the UK's oil and gas resources.

  • Prevent environmental damage.

  • Uphold health and environmental standards.

  • Protect the taxpayer from any residual liability.

Lease/licence/concession term

The Oil and Gas Authority (OGA) acknowledges that it is not desirable for production to cease simply because the term of the licence has expired, and therefore the OGA has a policy of extending licences where the relevant criteria are met (see Question 6). Typically, the OGA extends the term of a licence where a field is well-managed and there is continuing production, but in some circumstances the OGA also extends the term where production has not yet begun, but a discovery is very close to becoming a producing field when the licence expires.


A small annual charge is payable under each licence (called a rental). Rentals are charged at an escalating rate on each square kilometre the licence covers at that date. This method of calculating the rental provides an incentive to licensees to surrender acreage they do not want to exploit and to focus on their retained acreage.

The OGA levy

A new levy on oil and gas 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 licensees are jointly and severally liable for the amount of the levy). It is anticipated that the amount will be paid in full by the operator of the licence, and split between the various licensees in proportion to their participating interest in the licence. The amount of the levy for the period from 1 April 2016 to 31 March 2017 is:

  • Offshore production licence (pre-production): GB£6,808.65.

  • Offshore production licence (in production): GB£64,951.96.

  • Offshore exploration licence: GB£6,808.65.


Under the Model Clauses, the licensee indemnifies the Secretary of State against any third party claims arising in relation to the licence or anything done pursuant to it. The Model Clauses do not distinguish between operators and non-operators in relation to their liability. All licensees under the licence are jointly and severally liable for operations conducted under the licence. The Model Clauses are intentionally broad to ensure the widest possible interpretation and recourse the OGA to all of the licensees.


There is no UK national oil company with a direct involvement in oil and gas exploration and production activities, these activities 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.

See Question 10 for further information on the transfer of rights under the licences.

9. How are such leases, licences or concessions awarded?

The Oil and Gas Authority (OGA) is now responsible for issuing licences through competitive licensing rounds that generally take place every year. The Secretary of State's policy objective in a licensing round is to maximise successful and expeditious exploitation of the UK's oil and gas reserves. 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. The OGA must follow a set procedure when issuing petroleum licences, including the publication of an invitation for applications in the European Journal at least 90 days in advance (Directive 94/22/EC on the conditions for granting and using authorisations for the prospection, exploration and production of hydrocarbons (Hydrocarbons Licensing Directive), as implemented in the UK by the Hydrocarbons Licensing Directive Regulations 1995). Before awarding licences (or approving the transfer of a licence), the OGA must be satisfied that the applicant meets certain criteria. The Department of Energy and Climate Change (DECC) previously issued guidance on these requirements with each licensing round. The DECC focused on financial capacity and technical expertise, and placed particular emphasis on the technical capacity of the would-be operator.

On 6 November 2014 the Secretary of State announced that offers of awards for licensing in the 28th Seaward Licensing Round had been made.

On 28 July 2014, the Energy Minister invited applications for licences in the fourteenth Landward Licensing Round (applications closed on 28 October 2014). On 17 December 2015, the OGA announced that 159 onshore blocks under the fourteenth licensing round were being formally offered to successful applicants.


Transfer of rights

10. How are oil and gas rights transferred?

Licences cannot be sold, transferred, assigned or otherwise dealt in without the consent of the Secretary of State. The Oil and Gas Authority (OGA) provides that it 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 the technical and financial capacity of the assignee.

A change in control of an assignee is also a ground for revocation (unless such further change of control as the Secretary of State may direct takes place within a certain time). However, there is no express provision in the Model Clauses or the legislation for the granting of consent by the Secretary of State before the change in control. The OGA acknowledges that this may lead to a request for comfort that the Secretary of State will not exercise this power. The OGA is generally willing to consider these requests but will not give a formal confirmation. The OGA's policy is that a licensee must be able to demonstrate that a change of control will not prejudice its ability to meet its licence commitments, liabilities and obligations.

The creation of a charge on a licence also requires the consent of the Secretary of State. To facilitate transaction financing and to dispense with the need to obtain prior consent, an "open permission", which is a form of automatic consent, applies to any fixed or floating charge or debenture. This open permission does not apply where the licensee's interest in the licence is assigned on entering into the facility, whether under the terms of the security or by operation of law. It is a condition of the Open Permission that the licensee must give notice to the OGA within ten days of creation of the charge, providing information about the:

  • Date of the charge.

  • Size of the loan secured.

  • Licences affected.

  • Identity of the chargee.



11. What payments are payable by oil and gas interest holders to the government?

The taxation regime that applies to profits derived from oil and gas production in the UK and UK Continental Shelf (UKCS) was made up of three main components (following the March 2016 Budget, this will be reduced to two main components):

  • Petroleum revenue tax (PRT). This is a field-based tax charged on the profits arising from oil and gas extraction of individual oil fields and not in relation to the aggregate profits from all oil fields owned by each relevant company. PRT only applies to fields for which development consent was given before 16 March 1993. Ring fence corporation tax and the supplementary charge (see below) are also payable on profits from these fields, but PRT is deducted when calculating these charges. PRT is currently levied at a rate of 35%. However, in the March 2016 Budget, the Chancellor of the Exchequer announced that PRT will be reduced to 0% for chargeable periods ending after 31 December 2015.

  • Ring fence corporation tax (RFCT). This is a modification of the corporation tax that applies to all companies by way of a "ring fence". In contrast to PRT where each individual field is separately ring fenced on a field by field basis, RFCT includes all oil and gas exploration and production activity carried on by the relevant company. It aims to prevent profits from oil and gas extraction activities and rights in the UK and UKCS being reduced for tax purposes by the setting off of losses from other trading activities or by excessive interest payments and applies regardless of when development consent was granted. The profits from oil and gas extraction activities and rights are "ring fenced" and treated for tax purposes as a separate trade, so that only losses derived from these activities can be set off against profits from these activities. Since 1 April 2008, the main rate of RFCT has been fixed at 30% and the UK Government has announced that it will remain at 30% despite the phased reduction in the main rate of Corporation Tax on non-ring fence profits over recent years (from 30% in 2008 to the current rate of 20% and scheduled to fall to 17% by 2020). The small profits rate of RFCT is currently 19%, with a marginal rate applying between the small and main rates. RFCT liabilities are based on the book profits of the company, which are then adjusted to arrive at the taxable profits. Deductions are available for items such as:

    • plant and machinery allowances;

    • research and development;

    • expenditure on mineral exploration and access; and

    • decommissioning.

    However, there are restrictions on the use of interest on borrowings to reduce ring fence profits.

    The ring fence expenditure supplement (RFES) allows ring fence companies to uplift the value (by 10%) of losses or pre-trading expenditure to maintain their value until they can be set against future profits. Finance Act 2015 extended the RFES from six to ten years for all (both onshore and offshore projects) ring fence oil and gas losses and pre-commencement expenditure incurred on or after 5 December 2013.

  • Supplementary charge. This is also a tax imposed on profits arising from any ring fenced activities but excludes finance costs. It was originally introduced in 2002 and set at a rate of 10%. However, the UK Government subsequently revised the rate of the supplementary charge several times.

    The rate of the Supplementary Charge is currently 20%. However, in his March 2016 Budget, the Chancellor of the Exchequer announced that it will be reduced to 10% for accounting periods beginning on or after 1 January 2016.

    To support onshore oil and gas exploration, the Finance Act 2015 introduced a new basin-wide investment allowance, applicable to investment expenditure incurred on or after 1 April 2015 in both new and existing fields and infrastructure within the ring fence tax regime. The new allowance exempts a proportion of a company's adjusted ring fence profits (an amount equal to 62.5% of qualifying capital expenditure) from the supplementary charge.

    For high pressure, high temperature fields in a designated cluster area, the Finance Act 2015 also introduced an allowance that reduces a company's adjusted ring fence profits subject to the supplementary charge by an amount equal to 62.5% of capital expenditure and certain non-capital expenditure incurred in the designated cluster area.

12. Does the government derive any other economic benefits from oil and gas exploration and production?

An annual rental is payable under each licence (see Question 8). However, the UK Government derives the majority of its revenue from oil and gas through taxation. The UK Government does not derive any other economic benefits from oil and gas exploration and production. In the past, a royalty regime applied, but this was abolished from 1 January 2003.

Fields are normally developed by a number of companies who hold licences. These companies typically work together under a joint venture arrangement and appoint a company to act as the field's operator. The operator is responsible for organising all major works, although the other joint venture partners play an active role in the decision making process and must pay their proportional share of all costs.

13. What taxes and duties apply on import and export of oil and gas?

Value added tax (VAT)

All non-UK resident companies that make taxable supplies in the UK for VAT purposes must register for UK VAT. UK resident companies must register for VAT if the value of their taxable supplies exceeds the VAT registration threshold (from 1 April 2016 GB£83,000 per year in relation to VAT taxable turnover). Where a VAT registered entity incurs input VAT on goods and supplies it purchases, any such input VAT is generally recoverable to the extent that the entity makes taxable supplies for VAT purposes.

VAT is potentially chargeable on all supplies of goods and services made in the UK and its territorial waters (up to the 12-mile limit). There are different applicable VAT rates depending on whether the supply of oil is for domestic or commercial use.

Import VAT is generally due on imports (whether or not any customs or excise duty is chargeable or relieved), although this may be suspended or deferred where certain reliefs apply. It is also possible to defer the payment of VAT on certain items and to trade specified commodities in free circulation within the EU free from VAT within a fiscal warehouse. Where import VAT is due (whether at the time of import to the UK or on the removal from a fiscal warehouse) payment may be deferred by holders of an HMRC deferment authorisation.

From 1 January 2011, imports of natural gas by any means (including by tanker and pipeline) and in all forms (including LNG) are exempt from import VAT.

Customs duty

All goods imported into the UK from outside the EU, including fuels, are potentially liable to customs duty. For these purposes, the UKCS, being the area beyond the 12-mile limit, is outside the EU. Any customs duty due is payable at the time of importation of goods except when entered for warehousing or cleared on remission of duty under a specified relief regime (for example, relief from duty is permitted in certain circumstances on oil intended to be exported after processing).

Excise duty

Oil becomes liable to excise duty either when it is imported, or when it is produced in the UK and delivered for domestic use within the UK from a refinery and certain other premises.

The current rates are:

  • GB£0.5795 per litre for unleaded petrol.

  • GB£0.3770 per litre for aviation gasoline.

  • GB£0.6767 per litre for light oil (other than unleaded petrol or aviation gasoline).

  • GB£0.5795 per litre for heavy oil.

Excise duty is suspended while the oil is held in an approved warehouse. LPG is not liable to excise duty unless it is set aside or used as a road fuel. The main constituent of natural gas (methane) is not liable to excise duty. Relief from excise duty is available for oil put to use in an industrial process under the Industrial Relief Scheme (known as the "Tied Oils Scheme").

Climate change levy

The climate change levy (CCL) is an environmental tax on downstream activities and is chargeable on supplies of commodities used as fuels for lighting, heating and power by business consumers (where no exclusion or exemption applies). There are broadly four categories of taxable commodities:

  • Electricity.

  • Natural gas as supplied by a gas utility.

  • Petroleum and hydrocarbon gas in a liquid state (including LPG).

  • Solid fuels.

The levy is applied at a specified rate per nominal unit of energy (per kilowatt hour (kWh) or per kilogram).

The rates from 1 April 2016 are:

  • 0.559 pence per kilowatt hour for electricity.

  • 0.195 pence per kilowatt hour for gas supplied by a gas utility or any gas supplied in a gaseous state that is of a kind supplied by a gas utility.

  • 1.251 pence per kilogram for any petroleum gas, or other gaseous hydrocarbon supplied in a liquid state.

  • 1.526 pence per kilogram for any other taxable commodity.

While the exemption for renewable source electricity has now been removed (effective 1 August 2015), there are still exemptions for supplies:

  • Used in some forms of transport.

  • Used to produce other forms of energy.

  • To good quality combined heat and power schemes.

  • Not used as fuel.

UK residents who import taxable commodities and make supplies to end-users, or who are themselves end-users of taxable commodities, must register for the CCL. Importers who do not themselves use taxable commodities, but who sell them on to wholesalers or retailers (as opposed to end-users), are not required to register or account for CCL provided they obtain the necessary notifications from customers, which state the customer's intention to sell on the commodities.

For non-UK residents who make taxable supplies and who are not a utility, the liability to register and account for the main rates of CCL due rests with the person to whom the supply is made, based on their own taxable use or taxable supplies to business customers.


Transportation by pipeline

14. What regulatory requirements apply to the construction and operation of oil and gas pipelines?

Oil pipelines

Different requirements apply depending on whether the pipeline is:

  • Offshore.

  • Onshore.

Both offshore and onshore pipeline safety is governed by the Pipelines Safety Regulations 1996, made under the Health and Safety at Work etc. Act 1974 (HSWA), enforced by the Health and Safety Executive (HSE). These Regulations apply to pipelines in Great Britain, and also offshore by virtue of the Health and Safety at Work etc. Act 1974 (Application Outside Great Britain) Order 2013. The Regulations do not apply to certain pipelines listed in Schedule 1 (such as pipelines used for the conveyance of air, water vapour or steam). To ensure safe operation and use of the pipeline, the duties of a "pipeline operator" include:

  • Design.

  • Materials.

  • Construction and installation.

  • Operation.

  • Modification.

  • Maintenance and decommissioning of pipelines.

  • Additional duties in relation to major accident hazard pipelines (MAHP) (pipelines conveying dangerous fluids listed in Schedule 2).

A "pipeline operator" is defined as a person who has control over the conveyance of fluid in the pipeline or, if not yet known, the person commissioning the design and construction. The pipeline operator must notify HSE at the end of the concept design stage, before commitment to major expenditure, and at least six months before the commencement of construction of a MAHP. This triggers discussions between the operator and HSE regarding proper construction and safe operation. The operator also has to give at least 14 days' notice to the HSE of its intention to bring the MAHP into use. Further notifications are required for:

  • Change of operator.

  • Major modifications to the pipeline and fluid.

  • Cessation of use of the pipeline.

During the design phase and before it is finalised, the pipeline operator must prepare a major accident prevention document (MAPD), which is submitted to HSE. Its purpose is to demonstrate that:

  • All hazards with potential to cause a major hazard have been identified.

  • The risks have been evaluated.

  • The safety management system is adequate to control the hazard.

  • Adequate arrangements have been established for audit and reporting.


There is a network of approximately 45,000km of pipelines, umbilicals and power cables installed in the UK Continental Shelf (UKCS).

The key oil pipeline systems are:

  • Brent (to Sullom Voe terminal).

  • Forties (to Cruden Bay terminal).

  • Ninian (to Sullom Voe terminal).

These pipelines have been in place for many years and are owned and each is owned, operated and managed by a consortium of companies.

A third party seeking access to this infrastructure for the purpose of transporting and processing hydrocarbons must apply to the relevant owner of the pipeline system. There will then be negotiations between the third party operator and the pipeline owners. If successful, this will culminate in Construction and Tie-in and Common Services Agreements with provisions for ongoing services, agreed tariffs and allocation of risks. However, negotiating access to existing infrastructure proved problematic and was delaying field development. A non-statutory Code of Practice on Access to Infrastructure (ICoP) and Guidance Notes were introduced, which set out good practice for negotiating third party access. This ICoP was updated in 2012 following the review of the PILOT Infrastructure Access Group and reflects the provisions of the Energy Act 2011 giving the Secretary of State powers to settle disputes relating to access to infrastructure (see Question 15).

If the Secretary of State believes that parties have had a reasonable time to reach agreement and there is no prospect of them doing so, he may decide on his own initiative to issue a notice to secure access to the prospective user. The prospective user can also submit an Automatic Referral Notice (ARN) advising the Secretary of State that they will invite the Secretary of State to step in and exercise his statutory powers, unless negotiations for access are concluded in six months.

The OGA's Guidance on disputes over third-party access to upstream oil and gas infrastructure sets out the requirements and obligations on all parties. It also sets out the approach the OGA would take in handling applications and the principles the OGA would expect to be guided by in determining terms of access. On enactment of the Energy Act 2016, OGA will have further powers to attend negotiation meetings. If the negotiations fail, then the parties will be able to refer the dispute to the OGA for consideration and ultimately determination (Part 2, Chapter 2, Energy Act 2016).

On an offshore installation the limit of the pipeline, and, therefore, the limit of the application of the Pipeline Safety Regulations, is up to and including the emergency shut-down valve or primary shut-off valve off the pig trap where fitted, which connects the pipeline to the installation. The Offshore Installations (Offshore Safety Directive) (Safety Case etc) Regulations 2015 does not require safety cases for offshore pipelines but they do require the safety case to address all risks arising from pipelines (and associated apparatus, such as valves) connected to the installation with the potential to cause a major accident on the installation (as defined by Regulation 3 of the Offshore Installations and Pipelines Works (Management and Administration) Regulations 1995 as amended). Within that definition any part of a pipeline connected to the installation located within 500 metres of the main structure is deemed to be part of the installation. This obligation can be met by reference in the safety case to the relevant material in the MAPD.

Under the Petroleum Act 1998, a Pipeline Works Authorisation (PWA) issued by OGA is required before the construction and use or modification of any offshore oil and gas pipeline. Any change to the route or capacity of the pipeline requires a PWA Variation. The application will be forwarded to consultees for comment with responses due within 28 days. A Public Notice will then be published. When all objections are resolved, a PWA consent may be issued. It may take four to six months from receipt by the OGA to issuing the authorisation. While the PWA/PWA Variation is the principal consent, it is underpinned by a comprehensive environmental regime that imposes additional requirements, which are prerequisites to consent. In particular:

  • An Environmental Statement may be required under the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 (as amended). The required content of the Environmental Statement is set out in Schedule 2.

  • Consent to locate is required under Part 4A of the Energy Act 2008.

  • Written consent to deposit materials on the seabed (DEPCON), such as protective concrete mattresses, is required.

  • A permit under the Offshore Chemicals Regulations 2002 (as amended), for the use and/or discharge of chemicals during pipeline installation, commissioning, maintenance, repair and decommissioning operations.

If the proposed pipeline crosses over or goes near an existing pipeline, then the crossed pipeline owner and crossing pipeline owner will enter into a pipeline crossing agreement or proximity agreement, allocating risks and liabilities and providing consent. These agreements must accompany the PWA application.

There is a UK/Norway Framework Agreement 2005 in place for pipelines on the continental shelf that cross the UK/Norway boundary (apart from Vesterled) to encourage cross-boundary co-operation regarding reservoir effective exploitation and apportionment of costs.


For pipelines connected to onshore plants, the limit of the pipeline and, therefore, the application of the Pipeline Safety Regulations, is the primary shut-off valve or the primary valve off the pig trap that connects the pipeline to the plant (where fitted). A Pipeline Construction Authorisation (PCA) must be obtained for onshore oil and gas pipelines (except those of gas transporters) that are more than ten miles (16.093 km) in length (Pipe-lines Act 1962). Since the enactment of the Planning Act 2008, these pipelines are considered to be nationally significant infrastructure projects and therefore the application for consent under the Pipe-lines Act 1962 must be made to the National Infrastructure Directorate (NID) of the Planning Inspectorate under the Planning Act 2008. Pipelines that are ten miles or less are considered to be local pipelines, requiring planning consent from the local authority.

Gas pipelines

The key gas pipeline systems are:

  • CATS (from Central North Sea to Teesside).

  • FLAGS (between North Sea gas fields).

  • Fulmar (from Central North Sea to St Fergus gas terminal).

  • Frigg UK (from East Shetland Basin to St Fergus).

  • SAGE (Northern North Sea to St Fergus).

The FLAGS and Fulmar pipelines form the Segal System owned and operated by Shell-Esso.

The Gas Safety (Management) Regulations 1996 apply to all gas transporters (for example, gas shippers and terminal operators). Under the Regulations no person may convey gas in a network unless he has prepared a safety case containing the particulars set out in Schedule 1 and that safety case has been accepted by HSE before operations begin. A thorough review of the safety case must take place at least every three years. Reference to a "network" is a reference to a connected network of pipes used for the conveyance of gas from a gas processing facility or a storage facility except a connected network of pipes used exclusively for conveying gas to non-domestic premises. Therefore, the network starts from a gas processing/storage facility importing gas into the UK but does not include the facility. However, where a pipeline is used to convey gas from the UK, it will be necessary for the gas transporter on that pipeline to prepare and have accepted a safety case.

15. Is there a system of third party access to pipelines and other infrastructure?

Access for developers of offshore oil and gas fields to upstream infrastructure for the purpose of transporting and processing hydrocarbons is a key element in maximising the exploitation of the UK's oil and gas resources. The third party access regime has a voluntary, industry-led component, but this is underpinned by a statutory regime.

The Code of Practice on Access to Upstream Oil and Gas Infrastructure on the UKCS (ICoP) was launched in 2004, and revised and updated in 2012. Its purpose is to facilitate the utilisation of infrastructure for the development of remaining UKCS reserves through timely agreements for access on fair and reasonable terms, where risks taken are reflected by rewards. It provides a framework for oil and gas infrastructure owners and users of the process that must be followed in seeking, offering and negotiating access to oil and gas infrastructure on the UKCS. The ICoP applies to the processing and conveyance of all UK oil and gas throughout the hydrocarbon production and supply chain from wellhead through to receiving terminals and initial onshore processing facilities, including:

  • Onshore oil and gas terminals and pipelines that handle oil up to the point at which it has been stabilised.

  • Gas prior to the point at which it enters into the National Transmission System (NTS).

The ICoP does not apply to access to the NTS, interconnectors or LNG import terminals.

The ICoP is intended to clarify, streamline and facilitate the timely resolution of access requests on a negotiated, non-discriminatory basis. The ICoP is voluntary and is not legally binding. However, the OGA encourages parties to follow the ICoP and if the OGA becomes involved in a dispute about third party access (see below), then one of the many factors it considers is whether the parties have followed the ICoP.

Owners of upstream infrastructure are required to make available information regarding available capacity for that infrastructure. Third parties wishing to obtain access to such facilities must enter into more substantive discussions with the relevant infrastructure owners/operators. To facilitate such discussions, "bona fide enquirers" are required to provide certain information, including a broad outline of the development, to the infrastructure owners/operators. Following receipt of this information, infrastructure owners/operators should provide such additional information as may be appropriate to successfully conclude a commercial agreement. Where a party that seeks access to upstream oil and gas infrastructure cannot agree rights of access with the owner, it has the right to apply to the Secretary of State for a notice granting the relevant rights. The Secretary of State will consider such an application only if he believes the:

  • Parties have had reasonable time in which to reach an agreement.

  • Granting of the rights will not prejudice the:

    • transportation or processing of quantities of petroleum that the infrastructure owner could reasonably be expected to require; or

    • rights of other third parties with respect to the infrastructure.

If the Secretary of State decides to accept the application and issues a third party access notice, this notice may be subject to various conditions, including any conditions the Secretary of State considers appropriate to ensure that no person suffers a loss due to the mixing together of substances being transported or processed using the relevant facility.

Importantly, the Secretary of State can issue an access notice under his own initiative, where parties have had reasonable time in which to reach an agreement and there is no realistic prospect of an agreement being reached.

A similar regime under the Gas Act 1995, as amended by the Energy Act 2011, applies to downstream gas processing facilities (for example, facilities that process gas for the purpose of the gas being put into storage, an LNG import or export facility, a gas interconnector or a distribution system pipeline).


Health, safety and the environment

Health and safety

16. What is the health and safety regime for oil and gas exploration and extraction, and transportation by pipeline?


The health and safety legislative regime in the UK, including offshore, is robust, complex and far reaching. The primary piece of legislation is the Health & Safety at Work Act 1974 (HSWA). This imposes criminal liability on both companies and individuals who are in breach. The penalties include unlimited fines and imprisonment. Additionally, there are extensive regulations that apply to the oil and gas industry, imposing almost strict liability and some also trigger civil liability. The legislative regime must be read together with the guidance documents produced by the regulator, the Health and Safety Executive (HSE). Guidance from the HSE is considered to be best practice and must be complied with. International health and safety standards are also relevant when considering the extent to which a company has complied with best practice.

HSE's Energy Divison (ED) is responsible for regulating the risks to health and safety arising from work activity in the offshore oil and gas industry on the UK Continental Shelf (UKCS).

Where there has been a fatality, the provisions of the Corporate Manslaughter and Corporate Homicide Act 2007 (CMCH) apply. This imposes criminal liability on companies where there has been a "gross breach" of a relevant duty of care. There is no individual liability under the CMCH. However, individuals can still be prosecuted for manslaughter (culpable homicide in Scotland) at common law.

The UK oil and gas industry straddles both the Scots law and English law jurisdictions. The practice of investigation is the same, with inspectors using the same powers, guidance and techniques. They will gather evidence, take statements, seek specialist advice and prepare a report. The report will be assessed in line with the HSE Enforcement Policy (EPS) and use the Enforcement Management Model (EMM) to reach a decision on proportionate enforcement. However, there are significant differences in process and procedures between Scotland and England that have a material impact on the way the law is enforced. In Scotland, the Inspector submits his report to the Crown Office Procurator Fiscal Service (COPFS) following an incident. COPFS makes the final decision on whether it is in the public interest to prosecute and they conduct the prosecution. However, in England and Wales, the HSE is the prosecuting authority and decides whether to prosecute and then conducts the prosecution. In Scotland there is also a requirement for evidence to be corroborated before a conviction can be obtained but this does not apply in England and Wales.

The HSWA imposes almost strict criminal liability on all employers, who are under a duty to ensure the health and safety of all those affected by the conduct of such employer's operations, so far as is reasonably practicable. This duty therefore applies to all employees, contractors and third parties (including, visitors and members of the public). It is a complete defence to any charge under section 40 of the HSWA if an employer can prove that all reasonably practicable steps were taken to avoid the breach. However, the onus of proof is on the defendant to prove this. Individual officers, managers and directors whose neglect, consent or connivance contributed to the breach can also be prosecuted under the HSWA and imprisoned if convicted. Under the HSWA it is the duty of every employee while at work to take reasonable care for the health and safety of himself and of other persons who may be affected by his acts or omissions.

Following the Piper Alpha disaster in 1988, which claimed the lives of 167 oil workers, Lord Cullen's public inquiry led to sweeping changes to the regulatory regime. As a result, "duty holders" (as defined in the legislation) are required to:

  • Prepare a safety case that demonstrates they have the ability and means to control major accident risks effectively that is accepted by the HSE.

  • Consult the installation's safety representatives in the preparation, revision or review of the safety case.

  • Operate the installation in compliance with the arrangements described in the current safety case.

  • Implement effective measures to prevent uncontrolled releases of flammable or explosive substances.

  • Maintain the integrity of the installation's structure, process plant, temporary refuge and all other equipment.

  • Maintain the integrity of the wells and the pipelines throughout their lifecycle (this applies to well operators and pipeline operators).

  • Prepare a plan for dealing with an emergency should one occur.

The establishment of a safety case regime was the central recommendation of Lord Cullen's report into the Piper Alpha disaster. This was that the operator or owner of every offshore installation must prepare a safety case and submit it to the regulator for acceptance. The cornerstone of the offshore safety regime is the Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015 (SCR). The new regulations were as a result of the EU Offshore Safety Directive 2013/30/EU and the safety case now incorporates the additional requirements of the EU Offshore Safety Directive. In addition there is an HSE/DECC Guidance to the SCR.

The SCR came into force on 19 July 2015. They apply to oil and gas operations in external waters (the UK's territorial sea or designated areas within the continental shelf (UKCS)). They replace the Offshore Installations (Safety Case) Regulations 2005 in these waters, subject to certain transitional arrangements. Activities in internal waters (for example, estuaries) will continue to be covered by the Offshore Installations (Safety Case) Regulations 2005 and its guide L30.

The main aim of the SCR is to reduce the risks from major accident hazards. The SCR also aim to increase the protection of the marine environment and coastal economies against pollution and ensure improved response mechanisms in the event of such an incident.

In addition, the following regulations are central to the offshore regulatory regime:

  • Offshore Installations (Management and Administration) Regulations 1995 (as amended)(MAR).

  • Offshore Installations (Prevention of Fire and Explosion and Emergency Response) Regulations 1995 (PFEER).

  • Offshore Installations (Design and Construction) Regulations 1996 (DCR).

However, there are many other relevant regulations such as:

  • Management of Health and Safety at Work Regulations 1999 (MHSWR).

  • Control of Major Accident Hazards Regulations 1999 (COMAH).

  • Provision and Use of Work Equipment Regulations 1999 (PUWER).

SCR. The SCR must be read in conjunction with HSE Guidance.

The SCR are complemented and supported by MAR, PFEER and DCR, which impose both civil and criminal liability on duty holders and consist of a mix of absolute duties and qualified duties, with the reasonable practicability defence applicable to some of the regulations but not others.

The safety case should be a "living document" that reflects the reality of the situation on the installation and a revised safety case must be submitted every three years, calculated from the HSE's acceptance of the original safety case or subsequent revision.

The "as low as reasonably practicable" (ALARP) principle is one that is not only central to the evaluation of safety cases but also to the entire offshore safety regime. According to the HSE, ALARP involves an assessment:

  • Of the risk to be avoided.

  • Of the sacrifice (in money, time and trouble) involved in taking measures to avoid the risk.

  • A comparison of the above.

This process can involve varying degrees of rigour that will depend on the nature of the hazard, the extent of the risk and the control measures to be adopted. The more systematic the approach, the more rigorous and more transparent it is to the regulator and other interested parties. However, duty-holders (and the regulator) should not be overburdened if such rigour is not warranted. The greater the initial level of risk under consideration, the greater the degree of rigour the HSE requires of the arguments purporting to show that those risks have been reduced ALARP.

MAR. MAR makes provision for:

  • Notification to the HSE in writing of the date of an installation's intended entry into or departure from relevant waters and any change of duty holder or owner.

  • Ensuring that the installation is at all times under the charge of a competent person appointed by the duty holder to manage on his behalf the installation and the persons on it.

  • The need for co-operation among duty holders.

  • A permit to work system, where, as a result of the kind of work that may be done or the circumstances in which work may be done, it is necessary for the health or safety of persons.

  • Comprehensible written instructions on procedures to be observed on the offshore installation to be brought to the attention of every person who is to do anything to which the procedure relates.

PFEER. These regulations provide that the duty holder must take appropriate measures to protect persons on the installation from fire and explosion and secure an effective emergency response. The duty holder must carry out, record and repeat as often as may be appropriate, an assessment. This consists of:

  • Identification of the various events that could give rise to a major accident involving fire or explosion or the need for evacuation, escape or rescue to avoid or minimise a major accident.

  • Evaluation of the likelihood and consequences of such events.

  • Establishment of appropriate standards of performance to be attained by anything provided by measures for ensuring effective evacuation, escape, recovery and rescue to avoid or minimise a major accident.

  • Otherwise protecting persons from a major accident involving fire or explosion.

DCR. The DCR are essentially divided into two parts, as reflected in HSE Guidance:

  • Integrity, workplace environment and other miscellaneous matters. DCR provides that the duty holder must ensure that an installation at all times possesses such integrity as is reasonably practicable. The duty holder must ensure that installations are designed and built so that, so far as is reasonably practicable:

    • it can withstand such forces acting on it as are reasonably foreseeable;

    • its layout and configuration, including those of its plant, will not prejudice its integrity;

    • fabrication, transportation, construction, commissioning, operation, modification, maintenance and repair of the installation may proceed without prejudicing its integrity;

    • it can be decommissioned and dismantled safely;

    • in the event of reasonably foreseeable damage to the installation, it will retain sufficient integrity to enable action to be taken to safeguard the health and safety of persons on or near it.

    The duty holder must also ensure that suitable arrangements are in place for maintaining the integrity of the installation, including suitable arrangements for:

    • periodic assessment of its integrity;

    • the carrying out of remedial work in the event of damage or deterioration that may prejudice its integrity.

  • Specific well aspects. The well-operator must ensure that a well is designed, modified, commissioned, constructed, equipped, operated, maintained, suspended and abandoned so that, so far as is reasonably practicable:

    • there can be no unplanned escape of fluids from the well;

    • risks to the health and safety of persons from it or anything in it, or in strata to which it is connected, are as low as is reasonably practicable.

    In order to comply with this duty an assessment must be made before the design of a well is commenced of the hazards in the geological strata and formations. All such matters must, so far as is reasonably practicable, be kept under review and modifications must be made to both design and procedures if there is any change.

    Wells must also be designed and constructed so that, so far as is reasonably practicable, they can be suspended or abandoned safely and there can be no unplanned escape of fluids from the well or the reservoir after such suspension or abandonment.

    Before any well operations are commenced, the well-operator must ensure that suitable well control equipment is provided for use during such operations to protect against blowouts.


See above, Exploration.


As far as pipelines are concerned, the legislation is again complex and far reaching. The main legislation, in addition to the HSWA, is:

  • Pipelines Safety Regulations 1996.

  • Gas Safety (Management) Regulations 1996.

  • Pressure Systems Safety Regulations 2000.

  • Offshore Installations (Safety Case) Regulations.

  • Control of Major Accident Hazard Regulations 1999.

  • The Control of Major Accident Hazards (COMAH) Regulations 2015, which came into force on 1 June 2015.

Responsibility for enforcing health and safety law for onshore and offshore MAH pipelines lies with the Specialised Industries Gas and Pipelines Unit in HSE's Hazardous Industries Directorate.

The Pipelines Safety Regulations 1996 set out requirements relating to safety in the design, construction, installation, operation, maintenance and decommissioning of pipelines.

The Regulations apply to all pipelines in Great Britain, and to all pipelines in territorial waters and the UK Continental Shelf. The conveyance of natural gas through pipelines to domestic and other customers is dealt with under the Gas Safety (Management) Regulations 1996, which require gas transporters to prepare a safety case for approval by the HSE.


Environmental impact assessments (EIAs)

17. Is an EIA required before extracting or processing onshore or offshore oil and gas?

The applicable regulations are:

  • Offshore Petroleum Production and Pipe-lines (Assessment of Environmental Effects) Regulations 1999.

  • Offshore Petroleum Production and Pipe-lines (Assessment of Environmental Effects) (Amendment) Regulations 2007.

An operator who wishes to carry out certain upstream activities must first make an assessment of the impact that the activity would have on the environment (environmental impact assessment (EIA)) and then summarise and present the conclusions of this in an environmental statement (ES), which must be submitted to the OGA.

For the purpose of the above regulations the relevant activities include:

  • Granting and renewal of production consents for field developments.

  • Drilling of wells (deep boring).

  • Construction and installation of production facilities and pipelines in the United Kingdom Territorial Sea and on the United Kingdom Continental Shelf (UKCS).

The OGA recognises that operators may employ independent specialist consultants to aid in the EIA process and preparation of the ES, but it requires operators to assure the quality of the work being done by third parties on their behalf and ultimately to be responsible for the preparation of the ES and the commitments set out in it.

Even before a licensing round takes place, a Strategic Environmental Assessment (SEA) is carried out by the OGA, which considers the environmental implications of potential offshore oil and gas activities.

Updated guidance has been issued by the OGA and communicated to oil and gas operators and/or Mobile Drilling Unit (MoDU) operators after the Deepwater Horizon accident. The guidance relates to:

  • Environmental statements and direction applications.

  • Other environmental application submissions.

  • Oil pollution emergency plans.

  • Environmental reviews and inspections.

18. What are the different stages of the EIA?

The main stages of the EIA process are as follows:

  • The applicant advises the OGA of the project for which an environmental statement (ES) may be required.

  • The applicant then begins the EIA process. It is recommended that as part of this process applicants should consult interested parties such as local authorities and environmental conservation groups.

  • Once the ES has been prepared, it must be submitted to the DECC, and then a formal consultation process begins. As part of this, the ES is sent to relevant government departments such as the Department for Environment, Food and Rural Affairs, and environmental authorities such as the Environment Agency. DECC provides the applicant with a list of the bodies that must be consulted. A public consultation is also required, involving details being published in relevant newspapers.

  • Following the expiry of the public notice and after a technical assessment of the ES by the OGA, the OGA advises the operator of any comments arising from this assessment and those received from the environmental authorities and the public.

  • If all issues raised at the consultation phase have been resolved and the Secretary of State is satisfied that the project is unlikely to have a significant impact on the environment, then a formal letter is issued by the OGA confirming that there is no objection to consent being given for the activity.

  • Within six weeks from the date of publication of the details of the consent or approval, any person aggrieved by the decision (including the applicant, in relation to a refusal to grant consent) can apply to court for a judicial review of the decision.

  • There is no statutory timescale for the review of an ES, but the OGA's position is that it will always endeavour to review the applications in a timely manner. The OGA's official guidance states that it is good industry practice to allow a six-month period for approval before the proposed start of the project, although in practice it is usually possible for a decision to be made within a slightly shorter timeframe.


Environmental permits

19. Is there a permit regime for environmental damage or emissions produced during the extraction or processing of oil and gas?

The UK has a comprehensive framework for the management of the potential environmental consequences of oil and gas exploration and production, with a large number of different approvals and permits being required for various different aspects of operations.

In relation to greenhouse gas emissions, oil and gas production is covered by the EU Emissions Trading Scheme, as implemented in the UK by the Greenhouse Gas Emissions Trading Scheme Regulations 2012 (as amended).

The Offshore Combustion Installations (Prevention and Control of Pollution) Regulations 2013 require operators to obtain a permit in relation to any combustion equipment used on offshore installations, including burning fuel in turbines, internal combustion engines, fired heaters used to heat any medium, inert gas generators, or other similar fired processes. A "combustion installation" is defined as any technical apparatus in which fuels are oxidised in order to use the heat generated and cannot be operated without a permit.

The Offshore Chemical Regulations 2002 require operators to apply for permits for the use and/or discharge of chemicals in the course of all offshore oil and gas activities, including production, well, pipeline and decommissioning operations.

The Merchant Shipping (Oil Pollution Preparedness, Response & Cooperation Convention) Regulations 1998, and the Offshore Installations (Emergency Pollution Control) Regulations 2002 (together, the OPEP Regulations) are the main components of the legal framework under which the UK government regulates potential environmental incidents involving offshore installations, to ensure that preventative measures are in place to limit pollution. In particular, obligations are imposed on operators to implement robust emergency planning arrangements, and powers are reserved for the UK government to step in and take measures to enforce any necessary remedial actions.

For onshore operations, there are some differences in the environmental legislation. In particular, the Environment Agency in England and the Scottish Environment Protection Agency (SEPA) play a role in the issuing of some of the permits required to carry out onshore exploration and production.


Environmental concerns

20. Are there any specific government policies and/or incentives aimed at meeting the environmental concerns associated with the exploration and production of oil and gas?

Following the Deepwater Horizon incident in the Gulf of Mexico in April 2010, the European Commission concluded that the existing regulatory framework applying to the safety of offshore oil and gas operations in Europe, along with current industry safety practices, did not provide adequate assurance that risks from offshore accidents were minimised throughout the EU. As a result, on 28 June 2013, the EC published the Offshore Directive 2013/30/EU. The objective of this Directive is to reduce the occurrence of major accidents related to offshore oil and gas operations.

Health and Safety Executive's (HSE) and Department of Energy and Climate Change's (DECC) legislation has been updated to fully implement the Directive. This includes changes to existing legislation as well as introducing new requirements. The HSE implemented the majority of the health and safety requirements in the Offshore Installations (Offshore Safety Directive) (Safety Case) Regulations 2015. DECC also introduced new regulations to implement environmental and licensing requirements. The new regulations were laid in Parliament on 23 March 2015 and came into force on 19 July 2015. The Directive required the creation of an offshore competent authority. DECC and HSE have established the Offshore Safety Directive Regulator (OSDR).

The Infrastructure Act 2015 simplified the procedure for obtaining the right to use underground land 300 metres and below for the purpose of exploiting oil and gas. On 16 July 2015, the Government published the draft regulations, The Onshore Hydraulic Fracturing (Protected Areas) Regulations 2015, which define the protected areas in which hydraulic fracturing will be prohibited, giving further protection for groundwater and National Parks, Areas of Outstanding National Beauty, the Broads and World Heritage Sites, ensuring the process of hydraulic fracturing can only take place below 1200 metres in these areas (drinking water is not normally found below 400m).

The Environment Agency (EA) in England and Wales, and Scottish Environment Protection Agency (SEPA) are the environmental regulators who monitor the environmental aspects of shale gas fracking. The key regulation that governs how shale gas fracking operators in England comply with environmental laws is the Environmental Permitting (England and Wales) Regulations 2010. They provide industry, regulators and others with a single extended permitting and compliance system, called the Environmental Permitting System. This simplifies permit applications, amendments and variations for industrial emissions, for both industry and regulator.

On 17 December 2015, the Oil and Gas Authority (OGA) announced that 159 onshore blocks under the fourteenth Onshore Oil and Gas Licensing Round were being offered to successful applicants. Before the petroleum exploration and development licences (PEDLs) were granted, a detailed environmental impact assessment of the proposed blocks was carried out under the Conservation of Habitats and Species Regulations 2010 which was subject to public consultation. And consequently OGA is satisfied that the award of PEDLs in respect of these blocks will not impact on any protected European site.

Although OGA has sole authority to issue PEDLs throughout Britain, including Scotland, in January 2015 the Scottish Government announced a moratorium on onshore unconventional oil and gas extraction. They have used the requirement to have planning permission and SEPA consent prior to operations commencing as a means of halting shale gas fracking and coalbed methane extraction pending the outcome of a full public health impact assessment and public consultation with the industry. There are also demands for a public inquiry. Onshore licensing is part of the devolution settlements set out in the Scotland Bill and, accordingly, no new PEDLs were awarded in Scotland in the fourteenth Licensing Round.

The HSE monitors shale gas operations from a well integrity and site safety perspective. The applicable law is the Health and Safety at Work Etc Act 1974, and regulations made under the Act, such as the Borehole Site and Operations Regulations 1995 (BSOR) which applies to shale gas operations and the Offshore Installations and Wells (Design and Construction, etc) Regulations 1996 (DCR).

The HSE works with the Environment Agency (EA) and the Oil and Gas Authority (OGA) to regulate the industry. Planning authorities play a crucial role in how shale gas operations develop.



21. What are the regulations on the disposal of waste products resulting from oil or gas extraction or processing?

The Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (OPPC Regulations) impose a permitting system to control oil discharges from an offshore installation, with enforcement powers available to the UK government to require remediation of pollution in the event of an unauthorised discharge and to recover costs if it has to intervene if the operator fail to do so. These Regulations also apply in a restricted geographical area (per devolution settlement) to installations or pipelines established or maintained for the additional offshore energy-related activities of natural gas unloading and carbon dioxide.

Prior to any discharge of oil an Oil Discharge Permit is required and can be obtained by application to OGA on a Subsidiary Application Template (SAT) within the portal application process. This must be applied for at least 28 days prior to the proposed activity. Annex A provides additional information to help identify what discharges require a permit. These include well operations that result in drill cuttings, drill fluids, well interventions and also activities resulting in oil in produced water which may result, for example, from production at facilities tied-back to the host offshore installation. Normally the permit is issued to the operator or the person responsible for undertaking the work (such as the owner of the installation, duty holder, a company contracted to operate the installation on behalf of the owner) (the Permit Holder) who has overall legal responsibility for activities carried out under the permit and for ensuring that the conditions are met. The application can either be granted with conditions attached (reflecting OSPAR 2001/1/international regulatory limits if appropriate and also sampling and analysis requirements and maintenance of records and submission of permit returns), further information requested or refused. It will not be granted for operations which would not normally give rise to a discharge of oil to the sea.

All applications must include details of the measures to be taken to reduce the pollution by conducting an assessment of best available techniques and best environmental practices (BAT/BEP), including consideration of the most recent technologies and an environmental impact assessment. The quantity of oil, water and solids being discharged must be included in the application. If an environmental impact assessment has already been carried out, for example in an Environmental Statement, that can be used in this application. The OPPC application must also provide a summary of how environmentally critical elements related to the proposed operation are being identified and managed on the installation, in particular those pieces of equipment which, should they fail, could potentially give rise to larger volume releases or non-compliant discharges.

Applications for new oil discharge permits are subject to public notice in newspapers, except for those permit applications referred to in Regulation 5A(5) of the OPPC Regulations. The public notice must be published in newspapers on occasions that are likely to come to the attention of any persons likely to be interested in, or affected by, the discharge of oil to which the application relates. The public notice must:

  • Describe the application.

  • Give the address and time at which a copy of the application may be inspected.

  • State a date not less than four weeks after the date on which the notice is to be published by which any person may make representations to the Secretary of State at a specified address.

A suggested version of the notice is in Appendix C of the OPPC Regulations. Copies of the newspapers in which the notices appear must be provided to the Secretary of State. Applications that are not subject to public notice are applications for:

  • Time limited permit for drilling operations.

  • Pipeline operations.

  • Commissioning and decommissioning operations.

  • Well intervention/work-over operations.

If any changes are required to the permit, such as a treatment process modification or adding additional activities, then the Permit Holder must apply to OGA for a variation at least 28 days before the activity commences. DECC Environmental Inspectors will carry out periodic inspections. They monitor permit holder compliance and the ongoing suitability of the permit terms and conditions and can carry out formal reviews and vary the permit (with at least 14 days' notice so that the permit holder can make written representations as to why a variation should not be made).

A permit holder may be guilty of a criminal offence if it releases oil into the sea or allows such a release to continue. If there has been a breach of the permit conditions or any discharge of oil without prior authorisation, then these incidents require to be reported to DECC together with details of any release into the sea.

An Oil Discharge Permit is not required for the discharge of hydrocarbons that are subject to a permit under the Offshore Chemicals Regulations 2002 (as amended) which control the use and discharge (including injection) of offshore chemicals. The amended 2002 Regulations require an operator to apply to OGA for a permit for the use and potential discharge of chemicals such as low toxicity oil-based drilling fluids and discharge of oils controlled under the Merchant Shipping (Prevention of Oil Pollution) Regulations 1996 (as amended) (controlling machinery space discharges of oil routed via a drainage system) and the Merchant Shipping (Prevention of Pollution by Sewage and Garbage from Ships) Regulations 2006 (controlling galley waste discharges such as animal and vegetable oils which are routinely discharged from installations)) which both impose a permitting system.


Flares and vents

22. Are flare and vent regulations in place?

Consent from the Oil and Gas Authority (OGA) is required for venting (Energy Act 1976) and flaring (Petroleum Act 1998). OGA's policy is that it is committed to eliminating all unnecessary or wasteful flaring and venting of gas. Operators should seek to minimise this by implementing best practice at an early stage in the design of the development and by continuing to improve on this during the subsequent operational phase. The operator must carefully consider all operational activities in accordance with good oil field practices, taking into consideration plant uptime, efficient processing, handling, uses and transportation of gas.



23. What are the decommissioning obligations and liabilities that arise?

The decommissioning of offshore oil and gas installations and pipelines on the United Kingdom Continental Shelf (UKCS) is controlled through the Petroleum Act 1998, as amended by the Energy Act 2008.

The UK's international obligations on decommissioning are governed principally by the 1992 Convention for the Protection of the Marine Environment of the North East Atlantic (OSPAR Convention).

The Oil and Gas Authority (OGA) regulates decommissioning of offshore oil and gas installations and pipelines using legislation under the Petroleum Act 1998.

Section 29 notice. Decommissioning obligations arise when the Secretary of State serves a section 29 notice under the Petroleum Act 1998 to the operator of the field and each of the licensees, requiring them to submit a decommissioning programme. In the first instance this would include parties to joint operating agreements for installations, and owners for pipelines.

The 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.

Decommissioning programme. A decommissioning programme sets out the measures to decommission disused installations and/or pipelines, and will describe in detail the methods to undertake the work. In some cases this process can cover a wide range of activities such as radioactive material handling, removal of debris from the seabed and environmental monitoring of the area after removal of the installation.

Once the decommissioning programme is approved, following the OGA's review of the details including the cost estimates, the section 29 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.

As the objective of the regime is to shield the government from decommissioning costs, the OGA may also serve a section 29 notice on a wider group of parties, not just the current licensees, including any person having an ownership interest in the installation or pipeline, and a parent or associated companies of a licensee. 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. Importantly, section 34 of the Petroleum Act extends the right to issue a section 29 notice to anyone who, at any time since the issue of the first section 29 notice for the installation, was liable to have a section 29 notice served on it (that is, former licensees).

The licensee remains liable for decommissioning obligations until the section 29 notice is withdrawn. When an asset changes hands, the Secretary of State may release a former licensee from its section 29 obligations. In most cases, the section 29 notice is withdrawn once the OGA is satisfied that adequate financial security arrangements are in place in relation to the decommissioning liabilities. Such security arrangements are usually in the form of a Decommissioning Security Deed to which the Secretary of State may be a party, which ensure that the new incoming licensees can discharge the decommissioning liabilities. However, even if a former licensee is discharged from its section 29 obligations, in some circumstances the Secretary of State may use its claw-back power under section 34 to impose liability on that party.

Submitting a decommissioning programme. The OGA usually requests the submission of a decommissioning programme three or more years before cessation of production, although for smaller fields the OGA may require a programme at the time of approval of the final field development plan. If the OGA is not satisfied that the licensees will be capable of carrying out their decommissioning obligations then it may require them to provide security, such as a letter of credit, in order to reduce the risk to the UK taxpayer (who would otherwise bear this liability). The OGA also obliges companies to provide adequate financial information (including management accounts and revenue predictions) to enable the Secretary of State to assess whether decommissioning security ought to be provided at an earlier stage. Any funds set aside in a secure manner (such as a trust or other arrangement that was established on or after 1 December 2007) to meet decommissioning obligations will not be accessible to creditors under insolvency legislation.

Tax relief. As decommissioning is an inherent cost of doing business on the UKCS, obtaining tax relief for decommissioning costs is critical in determining whether to invest and a crucial factor in enabling participants to meet the overall cost of decommissioning. Tax relief for such costs is given at the point they are incurred and the decommissioning carried out.

Relief is given against RFCT and Supplementary Charge (but generally capped at 20%) as well as PRT (see Question 10). Typically, the relief will produce losses that can be carried back and set against earlier profits.

Security. Licence holders are required to post security for the cost of decommissioning, in accordance with the terms of a decommissioning security agreement. This is usually through letters of credit and facility agreements with third party financiers but such security has historically been calculated and posted on a gross (pre-tax) basis, taking no account of the tax relief the participant might obtain. This was largely due to the lack of certainty as to when and what tax relief would be available. In September 2013 the government introduced Decommissioning Relief Deeds, legal agreements between the government and oil and gas investors aiming to give the latter certainty as to the amount of security required to be tied up under their decommissioning security agreement.


Sale and trade

24. How is trade in oil and gas usually completed?

Traditionally, gas was mainly sold by producers to gas suppliers and large users at the onshore entry points into the National Transmission System (NTS), referred to as the "beach", under long-term gas supply agreements. While beach trades still take place, increasingly, gas trades are made once the gas enters the NTS, using the National Balancing Point (NBP). The NBP is a virtual trading location created under the Uniform Network Code, which governs the transport of gas through the NTS. The NBP 1997 contract is a standard contract commonly used for over-the-counter trades on the NBP. Other contracts, such as the ISDA with an NBP annex, are also used. Since 1999, an on-the-day commodity market has also operated. Participants in the gas trading market include:

  • Producers and suppliers.

  • Institutional investors.

  • Commodity traders.

  • National Grid Gas plc (the Transmission System Operator), who conducts trades on a daily basis to balance the network under the Uniform Network Code.

Oil trading consists of physical oil trades, as well as futures trading and over-the-counter derivatives. Participants in both the physical and paper crude oil markets include producers, refiners, trading houses and, increasingly, the commodity trading arms of investment banks.

25. Are oil and gas prices regulated?

Market regulators such as the Competition and Markets Authority and the Gas and Electricity Markets Authority (Ofgem) play a role in ensuring there are no abuses that could lead to price distortions. For gas, part of Ofgem's role is to ensure that the wholesale and gas supply markets remain competitive.


Enforcement of regulation

26. What are the regulator's enforcement powers?


The Department of Energy and Climate Change (DECC) Offshore Environmental Inspectorate enforces offshore oil and gas environmental regulations and permit conditions.

DECC can bring prosecutions against offshore permit holders and/or licensed operators. In general, DECC will pursue prosecutions where it considers:

  • The gravity of the alleged offence, taken together with the seriousness of any actual or potential pollution justifies this approach.

  • The general record and approach of the alleged offender warrants it.

  • There has been a reckless disregard of requirements enforced by the legislation.

The Oil and Gas Authority (OGA) has been granted the power to issue sanction notices in relation to petroleum related matters, including compliance with the terms of offshore licences. The OGA's enforcement activity falls into four categories of sanction notices:

  • Enforcement notices. These inform the recipient of the alleged breach of petroleum requirements and allow time for compliance with the prescribed conditions.

  • Financial penalty notices. These require the recipient to comply with the relevant petroleum requirement within a given timeframe and impose a specified financial penalty payable to the OGA in respect of the relevant breach.

  • Revocation notices. These revoke the petroleum licence of the recipient following a failure to comply with specified petroleum requirements. If such a notice is only given to one licensee in relation to a licence held by several licensees, the licence is not revoked in relation to the licensees other than the recipient.

  • Operator removal notices. These require the recipient licence holders to remove the operator from its position following a failure to comply with specified petroleum requirements.

Where a sanction notice is being issued in relation to a requirement applying jointly to two or more entities, the OGA may give the relevant sanction notice to only one of such entities, or to some or all of them jointly.

The OGA must issue a sanction warning notice before issuing a proposed sanction notice, setting out the alleged breach of petroleum requirements and allowing the recipient to make representations to the OGA in relation to such issues. The OGA is required to issue guidance on the amounts of the financial penalties it will impose but guidance has not yet been issued. It is also expected that the OGA will issue general guidance on its approach to enforcement.

The Health and Safety Executive (HSE) also has enforcement powers regarding violation of legislation and regulation related to health and safety, particularly HSWA. HSE inspectors derive their powers principally from Sections 20 to 23 of HSWA and associated legislation. They have, for example, power of entry to all work places, including docks and offshore installations, to inspect health and safety conditions and to investigate accidents to personnel working in a port or while loading or unloading a ship. They can similarly investigate accidents occurring to a ship's crew. Enforcement may include:

  • Serving notices on duty holders.

  • Withdrawing approvals.

  • Varying licences, conditions or exemptions.

  • Issuing simple cautions.

  • Prosecution.

  • Providing information or advice, in person or in writing.

The Maritime and Coastguard Agency (MCA) is responsible for enforcing all merchant shipping regulations in respect of occupational health and safety, the safety of vessels, safe navigation and operation (including manning levels and crew competency). The MCA and HSE share responsibility for enforcement in relation to vessels operating on coastal and inland waters, and have split this responsibility as set out in a Memorandum of Understanding between the Health and Safety Executive, the Maritime and Coastguard Agency and the Marine Accident Investigation Branch for health and safety enforcement activities at the water margin and offshore.

Fines and penalties

The OGA has the power to issue financial penalty notices carrying fines of up to GB£1million. 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.

New sentencing guidelines came into force on 1 February 2016, under which fines of up to GB£10 million can be imposed in the event of breach of health and safety legislation and regulations, or up to GB£20 million in the event of corporate manslaughter charges. The level of fines issued is now in part linked to the turnover of the relevant legal entity, such that larger groups are likely to be sentenced to heavier fines.

Recent prosecutions by the HSE have resulted in significant fines, including a fine of GB£3 million (plus over GB£150,000 in costs) issued to ConocoPhillips (UK) Limited in February 2016 for failures to conduct adequate risk assessment for offshore installations, in a case involving gas leaks that had put the lives of up to 66 workers at risk had an ignition occurred, though it did not result in any serious incident. The highest health and safety fine imposed to date remains the GB£15million fine imposed against Transco plc in 2005. This case involved systematic failures by the company leading to the explosion of a leaking gas mains installation in a residential area, in which four individuals were killed in their home.

27. Is there a right of appeal against the regulator's decisions?

The enforcement regime (see Question 25) entitles the permit holder or licensed operator to appeal against sanction notices issued by the Oil and Gas Authority (OGA) to a first tier tribunal, which is to be created for this purpose. The procedure for such appeals (including time frames) is yet to be established. Appeals against decisions of the Health and Safety Executive (HSE) can be brought through an independent appeals structure within HSE, within 21 days of the relevant decision.

Prosecutions introduced by any of the OGA, the HSE or the Maritime and Coastguard Agency can be appealed against in accordance with the normal rules for appeals in the UK.



28. Are there plans for changes to the legal and regulatory framework?

The UKCS Maximising Recovery Review Final Report (the Wood Review), published in February 2014, made four main recommendations for maximising economic recovery from the UKCS:

  • Government and industry should develop and commit to a new strategy for maximising economic recovery from the UKCS (MER UK).

  • Stewardship of the UKCS should move to a new, better resourced, arm's-length body, funded by industry.

  • The body should be provided with additional powers to implement MER UK.

  • The new body should work with industry to develop and implement new sector strategies, such as an exploration and decommissioning cost reduction.

In July 2014, the government published its formal response to the Wood Review, and set out its proposals for implementing the Wood Review's recommendations. The key proposal was the establishment of the Oil and Gas Authority (OGA) as a successor of the Department of Energy and Climate Change (DECC), as quickly as possible.

Andy Samuel was appointed as Chief Executive of the OGA, effective from 1 January 2015 and on 1 April 2015 a number of the DECC's functions were transferred to the OGA, such as:

  • Licensing.

  • Exploration.

  • Development.

  • Decommissioning.

The OGA will be responsible for maximising the cost effective recovery of oil and gas from the UCKS, in order to maximise the long-term added value to the UK as a whole, in accordance with MER UK. The OGA is headquartered in Aberdeen, with a significant presence in London. DECC submitted an Energy Bill to Parliament on 9 July 2015, which will complete the establishment of the OGA as steward and regulator of the UK's oil and gas reserves. Once the Bill achieves Royal Assent, the OGA will also be responsible for ensuring compliance with the legislation and carrying out the necessary enforcement activities. This Energy Bill is currently expected to be enacted in the first half of 2016, having passed the report stage on 14 March 2016.


The regulatory authorities

Oil and Gas Authority (OGA)

W www.gov.uk/government/organisations/oil-and-gas-authority

Main responsibilities. The OGA has recently succeeded DECC as the regulator of the offshore and onshore oil and gas sector in the UK, including oil and gas licensing, oil and gas exploration and production, oil and gas fields and wells, oil and gas infrastructure and carbon storage licensing.

Department of Energy and Climate Change (DECC)

W www.gov.uk/government/organisations/department-of-energy-climate-change

Main responsibilities. DECC is responsible for setting energy and climate change mitigation policies, and establishing the framework for achieving the policy goals in those areas.

Office of Gas and Electricity Markets (Ofgem)

W www.ofgem.gov.uk/Pages/OfgemHome.aspx

Main responsibilities. Ofgem is responsible for regulation of the downstream gas market in Great Britain.

Health and Safety Executive (HSE)

W www.hse.gov.uk

Main responsibilities. The HSE is an independent regulator, responsible for enforcing health and safety legislation in workplaces.

Environment Agency (EA)

W www.environment-agency.gov.uk

Main responsibilities. The EA is the environmental regulator for all onshore oil and gas operations, including shale gas, coal bed methane and underground coal gasification in England. In April 2013, Natural Resources Wales (NRW), a new body formed by the Welsh Government, took over the functions previously carried out by the Environment Agency in Wales.

Online resources


W www.legislation.gov.uk

Description. This is the official government website on which UK Legislation published. It does not always incorporate recent amendments. Users should take note of the warning and comments that are published on the website.

Contributor profiles

Philip Mace, Partner

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Professional qualifications. England and Wales, Solicitor

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