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The North Sea oil and gas industry is a significant contributor to the UK exchequer. In 2011/12 the industry contributed an estimated £11.2bn in corporation tax alone – around 25% of all corporate taxes.
From corporation tax to payroll taxes, oil and gas companies and their associated supply chains are important to HM Treasury, and (in providing employment and other social benefits) to the economy generally.
From a fiscal point of view, striking the right balance between short-term tax take on the one hand and encouraging investment to maximise production (and so long-term tax take) on the other has always represented a challenge for the government. This is especially the case now, as the North Sea basin matures and oil and gas reserves become harder and therefore more expensive to extract.
The industry’s reaction to the increase in the supplementary charge in 2011 from 20% to 32%, which led some companies to delay or freeze new exploration projects, highlighted the challenge for government.
The risk that the fiscal regime could drive companies to invest their exploration dollars in more tax-friendly jurisdictions, and leave some reserves in the basin unexploited, appeared to be a real one.
Since the 2011 increase in tax rates, the government has announced a number of important measures to encourage investment, from new field allowances to innovative proposals on decommissioning tax relief.
Encouraging investment also extends to onshore as well as offshore energy production, as illustrated by the recent proposals to create a targeted tax regime for shale gas. In this article we trace the recent history of the UK oil and gas tax regime, and summarise some of the key features that distinguish it from the general UK corporate tax regime. We then focus on some recent developments, including the measures referred to above.
Oil (which in the relevant UK tax legislation includes oil and gas) is subject to a special fiscal regime in the UK.
The territorial scope of UK tax on oil is wider than for many other taxes, covering activities on the UK mainland as well as on the UK continental shelf (UKCS). There are specific rules to ensure that non UK entities carrying on oil activities in the UK are subject to tax on their profits (through a deemed permanent establishment) as well as on gains made on disposals of assets or asset holding companies (through an extension of the usual territorial limits of tax on capital gains).
Three principal forms of direct taxation can apply to UK oil extraction and sale activities:
Broadly, RFCT and SC apply to all UK oil extraction activities while PRT now only applies (in addition to RFCT and SC) to fields that received development consent before 16 March 1993. As a result some older fields are subject to a higher level of taxation than newer fields. Royalty, another form of direct tax, was effectively abolished with effect from 1 January 2003.
Given that many practitioners may be unfamiliar with the basic form of these taxes, we have set out below a short description of each.
Petroleum revenue tax
Petroleum revenue tax (PRT) is levied on a participator’s share of profits from fields to which PRT applies (PRT fields). ‘Participators’ are usually the licensees of the PRT field. PRT is levied on a ‘field by field’ basis. Broadly, losses realised by participators in PRT fields can be carried forward or back against income of the participators from the same PRT fields.
Rather than using the statutory accounts of the taxpayer as a starting point, the calculation of profits and losses for PRT purposes is based on a strict and detailed set of statutory provisions. There are also various reliefs (such as ‘oil allowance’ and the ‘supplement’ or ‘uplift’) that can reduce the PRT charge for a given field.
A key feature of PRT, which again sets it apart from other direct taxes, is that it is deductible as an expense when calculating RFCT and the SC, thereby reducing the taxable profits that are then subject to RFCT or SC.
Ring fence corporation tax
Ring fence corporation tax (RFCT) is a modified form of UK corporation tax (CT). It applies to companies engaged in UK oil extraction activities (i.e. searching, extracting, transporting to land and initial storage of oil).
‘Ring fencing’ is an important concept in the legislation. Broadly, oil extraction activities are treated as a separate trade (a ‘ring-fenced trade’). Losses and expenditure which are otherwise deductible from the income of a general trade carried on by a person outside the ring-fenced trade cannot be set against the person’s profits within the ring fence. Losses within the ring fence can be carried back as far as 2002, or carried forward against future profits, or group relieved.
As with CT, the starting point in calculating the RFCT profits and losses for a company are that company’s statutory accounts. There are a number of tax rules that modify the accounting treatment, many of which apply to CT as well as RFCT, although some apply with important modifications. For instance, relief for capital expenditure is given through the capital allowances code, but there are a number of special provisions particular to oil-related expenditure, including many 100% first year allowances, which are commercially highly significant. The RFCT rules also contain restrictions on deductions in respect of financing costs, over and above the normal CT rules which govern such deductions.
Supplementary charge
The supplementary charge (SC) is calculated on virtually the same basis as RFCT save that no deductions are allowed for financing costs.
Special tax relief from the SC, known as field allowances, are available in the case of fields with given characteristics. For instance, fields associated with complex or challenging extraction technology such as small fields, ultra-high temperature or pressure fields and ultra-heavy oil fields receive field allowances. ‘Targeted’ field allowances have been introduced in recent years, usually to allow the development of fields which are otherwise economically unviable. These are discussed in greater detail below.
The tax regime: recent history
High up-front capital costs associated with oil and gas projects mean that investment is usually long term, making stability and certainty of the fiscal regime crucial for the industry. This has become ever more important as the opportunities for investment have widened, so that countries are in effect competing for infrastructure investment dollars.
The UK oil and gas tax regime has not been particularly stable; tax rates have changed frequently, different forms of taxation have been abolished or replaced and reliefs introduced and withdrawn. The regime is also relatively complex and in places significant uncertainty may arise as to its application in practice. These features are not perceived as conducive to long-term significant capital expenditure.
By way of example only, as already noted above, the 2011 sudden increase in SC from 20% to 32% has had a tangible effect on some UKCS investment. The table below summarises changes in the rates of the three main direct taxes over the last 20 years, as an indicator of some of the changes the regime has experienced, and the high effective tax rates that have always been a feature.
The considerable change in rates over the period is evident, resulting from a combination of the partial abolition of PRT, changes in the rate of RFCT and the introduction of SC. The rate of SC has more than trebled between 2006 and 2011. Many of the legislative changes responsible for the rate variation over the period were made with little or no advance warning or consultation.
The 2011 increase in SC has been one of the most controversial changes. In economic terms, whilst the SC increased by 12% ‘only’, given the already high tax rates, the effect was to wipe nearly 25% from the post-tax profits for some fields, with an effective tax rate for PRT paying fields rising to 81%.
According to the May 2011 Activity Survey update of the industry body Oil & Gas UK, this increase in SC immediately cut the value of all prospective investments in the UKCS by around 23%. Moreover, the survey results showed that 60 projects (one in four of new investments) were sufficiently impacted by the 2011 Budget that they had their probability of proceeding reduced.
Such projects comprised around 35 new field developments and 15 incremental projects and accounted for £22bn in potential capital investment.
Additionally, the survey suggested that 25 projects were sufficiently affected by the Budget that their probability of continuing was reduced to below 50%, indicating that around £12bn in capital investment was potentially put at risk.
Reduced investment in the North Sea risks having a detrimental impact on tax revenues from the sector. Oil & Gas UK’s estimation was that HM Treasury’s direct tax receipts from the UKCS would be cut by £15–20bn if investment in the 25 projects mentioned above were not to proceed. It is interesting to note that 2011 saw the largest fall in oil and gas output seen in the UKCS since the late 1980s.
The growing realisation that the UKCS fiscal regime as it stood post Budget 2011 could result in oil and gas reserves remaining unexploited (thus further reducing future tax revenues), has led to government introducing a number of initiatives aimed at stimulating investment. This is explored further below.
In recognition of the possible repercussions for the sector, the government has looked to a number of targeted measures to help those fields where the tax regime was perceived to be a barrier to investment in the UKCS.
We discuss the most significant of these below.
Ring fence expenditure supplement (RFES)
The increase in the RFES from 6% to 10% per annum announced shortly after the 2011 Budget is a measure designed to encourage investment in new exploration and development. The RFES is relevant to oil and gas explorers who will often incur expenditure at a point in time when they do not have any or sufficient profits against which to relieve it (i.e. at the exploration and development stage). Tax deductions for the expenditure are often therefore carried forward, potentially for a number of years. The RFES compensates companies for the fact that the value of unutilised losses/expenditure declines in real terms over time when not used, by ‘inflating’ the value of the expenditure/losses by a certain amount, for up to six years.
The government’s 2011 announcement that the RFES would be increased from 6% to 10% per annum was therefore welcome, and had an immediate impact: several companies which had previously announced a halt to oil exploration projects in the UK following the 2011 SC increase announced plans to resume such projects. For example Statoil, in confirming development of the Mariner oil field, highlighted the positive impact that the increase in RFES had on the project. HM Treasury estimated that the costs to it of the change was around £50m per year by 2015/16. By way of contrast, Statoil’s development of the Mariner oil field alone is expected to entail investment of more than US $7bn.
Field allowances
Field allowances are intended to provide an incentive for the development of new but commercially marginal oil and gas fields. Broadly, field allowances reduce the amount of ring-fenced profits charged to SC. Given the increase in SC to 32% in 2011, field allowances have become increasingly significant.
Field allowances do not affect the charge to RFCT (levied at the rate of 30%) which remains payable on all taxable profits from the field. Moreover, SC remains payable on all profits not protected by field allowances. However, the allowances are a useful means of targeting incentives for companies to invest in particular fields which might otherwise have proved uneconomic to develop.
Prior to FA 2011, field allowances were available only for particular types of ‘marginal’ oil and gas fields (e.g. ultra-heavy oil fields; ultra-HP/HT (high pressure / high temperature) fields; and certain small oil or gas fields or deep water gas fields). In 2011, the government extended field allowances to investment in fields that have previously been decommissioned, and promised to review the scope of fields qualifying for the field allowance generally; this was then followed by the introduction in 2012 of new and extended field allowances.
New measures introduced in 2012 through powers conferred under CTA 2010 s 349A included:
The government also introduced (through SI 2012/3153, which also enacted the other field allowance changes described above) a new field allowance for new shallow water gas fields, as a means to incentivise gas exploration. This allowance was striking in that it extended the scope of field allowances beyond difficult/marginal fields. An Oil & Gas UK press release issued at the time estimated that the new allowance should trigger development of specific gas projects involving expenditure of £2.4bn, the creation of 4,000 jobs and £600m of additional tax revenue. This for a relief that, on the government’s own estimate, should cost the exchequer only £20m per annum in reduced SC collection.
This was followed by the announcement of new targeted tax reliefs for so-called ‘brown field’ areas, aimed at incentivising investment in, and supporting continued production from, older fields in the North Sea. This was a significant further extension to the field allowance, which had typically been used to incentivise investment in ‘new’ fields, i.e. fields which had received their first development authorisation on or after 22 April 2009. HM Treasury predicted that the new allowances will reduce immediate tax revenues by around £100m a year. According to Oil & Gas UK’s 2012 Activity Survey plans exist to invest up to £82bn in the coming decade on existing and potential projects in the UKCS – with much of this investment relying on the introduction of these new brown field allowances.
Set in the context of falling North Sea tax revenues, and continued wider economic uncertainty, the extensions to the field allowance represent a concerted effort by government to use targeted field-specific tax reliefs, with a relatively modest up-front cost to the Exchequer, to unlock significant investment in the UK oil and gas sector. It is clearly hoped that such investment will in the longer term halt or even reverse the decline in North Sea tax revenues and extend the useful economic (and tax generating) life of many fields. In line with Oil & Gas UK and HM Treasury predictions, several projects, including the Solan field to the west of Shetland, with the potential to generate a significant net return for the exchequer, are already said to have moved forward as a result of these tax reliefs.
Shale gas
Most recently, the government has confirmed (in the 2012 Autumn Statement) that it will consult with industry with a view to introducing a new tax regime for shale gas, as part of a plan to stimulate investment in this important onshore source of energy. There is speculation that any new regime may take the form of relief from the SC, but specific proposals have not yet been published.
Any new shale gas regime appears intended to assist the industry through the early (and expensive) stages of its development and ensure that the UK’s shale gas reserves are properly exploited. The government perceives that this new measure will assist in unlocking investment in the UK, have the potential to create jobs and support UK energy security, and help in its policy to diversify the UK’s energy mix.
Another aspect of the government’s attempt to incentivise development of the UKCS is to remove barriers both to field transfers, and to investment generally, brought about by the tax treatment of decommissioning expenditure.
Decommissioning is very expensive: HM Treasury’s own estimate puts the cost (in 2011 prices) at £33bn.
Uncertainty about the future availability of tax relief for decommissioning expenditure has resulted in increased costs of investment in the UKCS, and affected UK oil & gas M&A activity generally, at a time when the UKCS basin has entered a ‘mature’ phase, with further investment and innovation needed to exploit existing reserves. This has been seen as a real barrier to new players entering the UKCS and to further investment.
To explain the issue it is first necessary to understand the nature and timing of tax reliefs available in the context of decommissioning as well as some aspects of the underlying regulatory framework.
Tax reliefs
On general principles, decommissioning costs are treated as capital account expenditure. As such, whilst provision for decommissioning costs is likely to be made in the accounts of the entity that will incur them, this does not give rise to a tax deduction against profits.
However, tax relief is available both against RFCT and the SC, and against PRT.
Capital allowances: There are specific provisions in CAA 2001 Part 2 Chapter 13 which provide 100% relief against ring-fenced profits for certain decommissioning costs. Broadly, the expenditure must relate to an approved abandonment programme and must be incurred on decommissioning plant or machinery which is, or forms part of, an offshore installation or submarine pipeline. Draft Finance Bill 2013 contains provisions to include expenditure on decommissioning certain types of onshore facilities as well.
Relief is only given when the expenditure is incurred, as opposed to any earlier time (such as when provision is made for the expenditure, or a legal commitment to incur the expenditure comes into existence).
However there are rules, introduced in the FA 2008 (now CTA 2010 s 42), which allow the relief to be carried back to accounting periods ending after 17 April 2002 in certain circumstances. Other provisions of CAA 2001 (for example, s 26) may also provide relief for certain decommissioning expenses. For example, there are provisions which provide relief for certain demolition costs, generally at a rate of 25%. Being more general in nature, these provisions could apply to a wider range of expenditure than that mentioned above.
Following FA 2012 and the introduction of CTA 2010 s 330A, tax relief for decommissioning expenditure is restricted to a rate of 20% in respect of the SC (so that where the rate of the SC is over 20%, as it is now, the relief will cease to be ‘full’ tax relief).
PRT deductions: The costs of decommissioning ‘qualifying assets’ are deductible against the PRT charge. As with capital allowances, relief is only available once the expenditure has been incurred, and again there are rules allowing the carry back of the relief against profits which were subject to PRT in earlier tax periods.
The regulatory framework
The regulatory framework for decommissioning offshore installations and pipelines in the UK sector of the North Sea is set out in Part IV of the Petroleum Act 1998 (the ‘Act’).
The UK has obligations in relation to decommissioning offshore installations under the United Nations Convention on the Law of the Sea of 1982 and the Convention on the Protection of the Marine Environment of the North East Atlantic (the OSPAR convention). A key feature of the OSPAR convention is the (binding) requirement completely to remove offshore installations from the sea bed unless a derogation is granted. This contrasts with the cheaper so-called ‘rigs to reefs’ policy in certain other jurisdictions, notably the US, where rigs may be permitted to remain in place. The requirement does not apply to pipelines which are not currently subject to international guidelines on decommissioning.
Key features of the decommissioning regime under the Act: The Act seeks to ensure, as far as is possible, that industry (rather than the UK taxpayer) pays its share of that cost.
Under the Act the Secretary of State can issue notices (commonly referred to as ‘section 29 notices’) to require a person to submit a programme setting out the measures which that person proposes to take regarding the abandonment of the offshore installation or pipeline covered by the notice, and to carry out (and pay for) such programme. Essentially, those receiving such notices are jointly and severally liable for the cost of decommissioning the relevant infrastructure.
Persons to whom section 29 notices can be issued in relation to offshore installations include the manager of the installation (usually interpreted by the Department of Energy and Climate Change (DECC) as the operator), current and former licensees, certain other parties to joint operating agreements, and (broadly) other associated companies of the above – hence allowing the secretary of state to gain access to the assets of the relevant person’s entire group.
Persons who can be issued with a section 29 notice in relation to submarine pipelines include those designated as owners of the pipeline by an order made by the Secretary of State, certain persons holding interests in the pipeline, and associated companies.
Under s 34 of the Act, where the secretary of state approves a decommissioning programme submitted to him under s 29, either he, or the persons who submitted the programme, may propose that another person should have a duty to undertake the programme. Such persons may include persons who were previously holders of section 29 notices, or were at risk of being served with one, in relation to the relevant infrastructure, going all the way back to the issue of the first section 29 notice in relation to the relevant infrastructure.
Current section 29 notice holders have ‘front line’ liability and DECC regards its powers under s 34 to be a ‘last resort’. A failure to carry out a decommissioning programme is an offence and the defaulting party may be liable for the costs of remedial decommissioning action taken by DECC (plus interest). DECC also has the power to require that a person who is subject to a section 29 notice (or to whom s 34 applies) provide security to DECC if DECC is not satisfied that such person is financially capable of complying with its decommissioning obligations.
Decommissioning security
As the regime is one of joint and several liability, industry participants who are jointly liable to decommission the same infrastructure will often seek to establish a decommissioning security trust fund (held by an insolvency remote trustee) to which they all contribute the necessary cash or security (in the form of cash, guarantees or letters of credit) to secure the costs of decommissioning. Such arrangements are called field-wide decommissioning security agreements (DSAs).
Oil & Gas UK (in conjunction with DECC) has produced a model form field-wide DSA which is customarily used by industry. Oil & Gas UK is currently working on revisions to that model form to take into account the proposed decommissioning relief deeds (discussed further below).
In the context of UKCS M&A transactions, the seller will want a ‘clean exit’ from any decommissioning liability and will therefore expect the buyer to indemnify the seller and its group against all decommissioning costs in relation to the assets being acquired. If there is no field-wide DSA in place which allows the seller to access trust funds if it is ever required to fund decommissioning, the seller may also want that indemnity backed up by a ‘bilateral’ DSA. Bilateral DSAs can take different shapes and there is no ‘model form’. That said, they customarily provide that buyers must provide sellers with security ranging from guarantees to cash or letters of credit, depending on the creditworthiness of the buyer from time to time.
Bilateral DSAs are customarily required by oil and gas majors (and other independents) selling assets in the UK North Sea in relation to fields where field-wide decommissioning security arrangements have not already been put in place.
Although each DSA is different and subject to negotiation between the relevant parties, security under both field-wide and bilateral DSAs is currently customarily posted on a pre-tax basis, as we discuss further below.
The problem
As already noted decommissioning is associated with significant expenditure, but although delayed, tax relief for such expenditure is in principle available. Against the background of the high effective rate of tax associated with the UKCS (ranging currently between 62% and 81%, see the table above), the value of the tax relief is also high. It is estimated, in the context of the £33bn projected decommissioning spend noted above, that tax relief would account to around £20bn.
When such significant tax relief is taken into account the true cost of decommissioning to industry is reduced, but this assumes that tax relief will, at the time decommissioning is undertaken and expenditure is incurred (i.e. the time when the tax relief becomes available, under current law), continue to be available, and that the person entitled to such relief has sufficient tax capacity against which to set such relief.
The question, in the context of agreeing the value of a decommissioning security package, is therefore whether the party requiring the security will be willing to accept it on a ‘net’, or post tax relief basis (in which case a significantly lower secured amount would be required) or on the higher ‘gross’ or pre-tax relief basis.
The party seeking security will obviously be keen to ensure that sufficient funds will be available to fund the decommissioning expense in the event of a default. In essence the question of whether to seek gross or net security is one of risk allocation – in this case the risk that tax relief will not in whole or part be available. Parties (including DECC) have usually requested security for decommissioning liabilities on a ‘gross’ basis, i.e. ignoring the value of any possible (but strictly not guaranteed) tax relief. This has become the usual ‘industry’ model for the granting of security, and as a result significant resources (representing amounts of tax relief) are tied up in security arrangements.
To understand in a little more detail why this approach has become the norm, it is necessary to understand the risks that full tax relief would not be available. The main risk is that there is no guarantee that the current value of PRT deductions and capital allowances will be maintained in the medium to long term. As a matter of principle Parliament may always legislate to amend, revise, restrict or eliminate current reliefs and the relatively frequent change in the UKCS tax regime does not support a high level of confidence within industry that the legislation will remain stable. The concerns of those addressing the matter in the context of the gross/net debate is perhaps heightened by the following:
A second concern relates to tax capacity: despite the enhanced rules on loss carry back, a party that found itself liable for the decommissioning expenses of other participants might find that it had insufficient tax capacity to utilise all such reliefs.
Given these matters, it is unsurprising that parties have had difficulty in quantifying the value of any tax relief that may be available on decommissioning. The approach taken by parties seeking security on a gross basis can therefore be understood as the only one guaranteed to ensure that, whatever changes are made to the tax system, there will be sufficient funds to meet the relevant decommissioning liabilities.
A contractual solution?
The government has in recent years become increasingly aware of the detrimental effect the uncertainty over tax relief for decommissioning has been having over UKCS investment, both in the context of M&A transactions and more widely. The government also seems to have recognised that any attempt to redress the problem cannot consist of new legislation only; as part of the current uncertainty is driven by the concern that any legislation would be reversed in the future, and that in principle it would always be within the power of parliament to do so.
To overcome this problem, and to remove the uncertainty over the value of decommissioning relief, the government has therefore proposed entering into a ‘decommissioning relief deed’ (DRD) with oil companies. The purpose of the DRD is (broadly) to entitle field owners to receive cash payments from the government to the extent that the tax law in force when the decommissioning takes place would provide less generous tax relief than would be the case at the date of Royal Assent to the Finance Act 2013. This is particularly the case in the event that a company is required by DECC to take on a third party’s liability for decommissioning, following that third party’s default.
Given the constitutional difficulties (and perhaps impossibility) of one government binding future governments not to change the law, the hope is that a contractual solution will provide sufficient certainty as to the availability of future decommissioning tax relief for sellers of oil and gas assets to be prepared to accept security on a ‘net’ basis rather than ‘gross’.
To this end, the draft Finance Bill 2013 contains legislation to allow government to enter into the DRDs with participants. A draft DRD has been published. Such a contractual arrangement, effectively guaranteeing a level of tax relief to companies in certain circumstances irrespective of future changes in law, is a highly innovative proposal and raises a number of interesting questions.
The final form of the legislation and the draft DRD remain subject to further consultation. Issues likely to be debated include the scope of so-called ‘clawback’ provisions in the DRD, which are designed to ensure that, by virtue of the DRD and any other payments received, a party is in no better position than it would have been in absent having to meet the decommissioning liability; as well as provisions limiting payments in the event of certain favourable changes of law, and the ‘anti-abuse’ rule contained in the terms of the DRD, designed to render ineffective transactions or arrangements entered into with a main purpose of obtaining a payment under the DRD.
Further discussions are also envisaged on the timing of payments under the DRD. This is likely to be relevant to whether parties will require bridge financing or otherwise meet timing costs in respect of the period between incurring decommissioning expenditure and payment under the DRD. It is interesting to note in this context that the proposals envisage that the DRD would be capable of being assigned by way of security, perhaps anticipating the need for doing so in the context of bridge finance.
There is much for industry to consider in the new legislation and draft DRD, although the initial response (reflecting the extensive consultation process to date) has been positive. Oil & Gas UK, commenting on the publication of the draft DRD, noted that:
‘The measure announced today will enable investors to secure a level of certainty on decommissioning tax relief that can be reliably factored into investment decisions and commercial decommissioning security arrangements.’
This expectation is echoed in the recitals to the draft DRD itself, which explain that the DRD’s aim is to ‘enable … security to be made or given or received net of tax relief’.
Both the method chosen to achieve that goal, through the use of enabling legislation and contractual instruments, and the form of the DRD itself, will no doubt be subject to further debate in the consultation scheduled to take place over the coming months. Alongside the consultation process industry is separately working on an updated model DSA; the extent to which this updated model agreement provides for security to be provided ‘net’ of tax relief, and the extent to which industry then adopts that model, will ultimately determine whether the government has succeeded in achieving its goals.
As a postscript to the DRD debate, the draft Finance Bill 2013 also contains a package of measures to correct anomalies in the tax regime affecting decommissioning (such as, for example, ensuring that relief is not lost where a third party funds the decommissioning). These changes are closely tied to the DRD process, as the aim of the DRD is to preserve for participants the legal position as it stands at Royal Assent of Finance Act 2013. This has given added impetus to the ongoing debate between industry and the government on the technical decommissioning tax relief provisions themselves; it is in all parties' interests that the legislation as it stands at Royal Assent of Finance Act 2013 is fit for purpose and does not itself create uncertainty.
The government now seems committed to using the tax system to encourage UKCS investment, and is willing to use less orthodox tools to bring certainty to the sector.
The UK oil & gas sector is and is expected to remain, for many years to come, a significant part of the UK economy. It generates directly a large proportion of UK tax revenue, and through the associated supply chain it provides many UK jobs. In this context we have sought to highlight how the UKCS tax regime has in recent years been characterised both by high effective tax rates, a high degree of complexity and frequent change. In short, successive governments have looked to the UK oil & gas sector when additional tax revenues have been required. However, there is now a growing realisation that in an industry where investment decisions involve significant expenditure and a long-time horizon, it is crucial to have certainty as to taxation, both in scope and in terms of applicable rates.
The government now appears committed to using the tax system to encourage UKCS investment. Targeted tax reliefs, aimed at encouraging development of what might otherwise be marginal fields, appear already to have resulted in significant increased investment in the UKCS at a relatively low cost to government. Such increased investment should result in increased tax revenue in the years ahead, so this represents a ‘win-win’ scenario for government and the sector as a whole. We would expect to see further similar targeted measures in the years ahead.
The government has also demonstrated that it is willing to use less orthodox tools to bring certainty to the sector. This is best demonstrated by the proposed use of contractual arrangements to achieve certainty over the availability of decommissioning tax relief. Such arrangements are needed to counter the uncertainty associated with the current UK regime: it is notable that in jurisdictions where there is no strong perception of uncertainty, such as Norway, similar measures have not been required. However it is probably not possible to create certainty (at least in the short term) through legislation alone, hence the need for a more creative solution.
It will certainly be interesting to observe the reaction of industry and government to the package of measures described above. Ultimately the success or failure of these is likely to be judged (from industry’s perspective) by the level of investment that we see in the UKCS in the coming years and (from the government’s perspective) by the tax revenues generated from the UKCS.
Isaac Zailer, William Arrenberg and Aurell Taussig are members of the Herbert Smith Freehills LLP energy tax team. They provide UK tax advice on upstream and downstream oil and gas work as well as 'green' and new energy sources, specialising in M&A work. They also advise on a range of corporate tax matters generally, including non-energy M&A, group reorganisations, real estate and cross-border work. Contact isaac.zailer@hsf.com (020 7466 2464); william.arrenberg@hsf.com (020 7466 2574); and aurell.taussig@hsf.com (020 7466 2451). Alastair Young is a corporate lawyer in the firm's energy team. He advises on international energy M&A and energy project development, and has recently acted on a number of high profile UK North Sea M&A transactions. Contact alastair.young@hsf.com (020 7466 2606).
More sector focus reports
Recent in-depth Reports examine the tax issues affecting the following sectors:
Reports on the retail and TMT sectors will be published in the coming weeks.
