1.1 The purpose of this document is to provide a basic description of the fiscal regime which applies to companies engaged in oil and gas extraction activities in the UK or on the UK Continental Shelf (UKCS). This chapter describes briefly the main elements of the fiscal regime which applies today and indicates how they fit together. Chapter 2-7 give more details about those elements of the existing regime which are administered by the HM Revenue & Customs Large Business Service Oil & Gas Sector (LBSOG) – formerly Oil Taxation Office (OTO), particularly Petroleum Revenue Tax (PRT). The document does not cover those aspects of corporation tax which are not specific to the oil and gas industry or features of the regime which do not apply today, such as the gas levy, Supplementary Petroleum Duty and royalty, all of which have been abolished.
1.2 Further information on aspects of the regime can be obtained from the contacts listed at the end of the document.
1.3 Over the last three decades of the twentieth century the UK had developed into one of the world's major oil producing countries. Successive Governments have had to develop a fiscal regime which provides sufficient financial incentive to companies to explore for and develop the nation's oil and gas reserves while at the same time ensuring that an appropriate share of the benefits accrues to the UK economy as a whole. Fiscal policy has also had to remain flexible enough to cope with significant fluctuations in oil prices over the last three decades.
1.4 In addition to the oil extraction industry itself there are numerous dependent industries which have evolved to support and supply developments on the UKCS. These rely to some extent on fiscal policy to help provide an attractive investment environment for oil companies in what is becoming an increasingly competitive global market for oil company resources.
1.5 All oil and gas in Great Britain and its territorial sea has belonged to the Crown since the Petroleum (Production) Act 1934 was passed. The same Act provided for the payment of royalties to the Government in the event of any oil or gas being produced. The 1958 UN Convention on the Continental Shelf gave countries with coastlines sovereign rights to explore for and produce the natural resources lying on or beneath their continental shelves. In 1964 the UK Government ratified the Convention and passed the Continental Shelf Act which extended the licensing powers of the Petroleum (Production) Act 1934 to the UKCS. A 200 mile limit was declared and median lines established in the waters surrounding the UK. These Acts provided the fiscal framework for the discovery and initial development of the first generation of offshore gas fields in the Southern Basin of the North Sea from the mid 1960s to the early 1970s. (Under the Petroleum (Production) Act (Northern Ireland) 1964, landward petroleum licensing in Northern Ireland is the responsibility of the Department of Economic Development.)
1.6 It became clear in the early 1970s that the UK would, within a few years, become a significant oil producer and, against the background of rising oil prices and the emergence of OPEC, the then Conservative Government began to review the UKCS taxation system. However, before the Conservative administration introduced any legislation to change the North Sea fiscal regime it was replaced by a Labour Government in 1974. The Labour Government brought in the Oil Taxation Act 1975, which still forms the basis of the PRT regime for oil and gas fields given development consent before 16 March 1993.
1.7 Exploration for and production of petroleum in Great Britain and on the UKCS can be undertaken only under the terms of licences issued by the Secretary of State for Trade and Industry. Licensees may carry out field development work and production only with the consent of the Secretary of State or under a development and production programme approved by him. Under the terms of a petroleum licence, any oil or gas won from fields in Great Britain and on the UKCS belongs to the licensee. But the powers to award licences and to withhold approval for development plans give the Government some direction and control over the way in which, and the rate at which, the nation's hydrocarbon resources are exploited.
1.8 The UKCS is divided by a grid into blocks averaging 100 square miles (260 square km). Many blocks have been sub-divided into one or more part blocks by relinquishments required periodically under most licences. Each block and part block has a reference number for licensing purposes. A licence can cover more than one block.
1.9 Applications for licences can be made only in respect of blocks or part blocks offered by the Secretary of State, usually in a licensing round. Applications-either from single companies or, more commonly, from consortia are assessed by DBERR (Department for Business, Enterprise and Regulatory Reform) (formerly the DTI) against a number of criteria, including financial and environmental management capability, technical competence and a programme of work to explore and appraise the prospectivity of the area applied for. Licences are awarded at the discretion of the Secretary of State, who must also approve any subsequent transfer of licence interests between companies.
1.10 DBERR also have responsibility for determining the boundaries of oil and gas fields for taxation purposes. This is done on the basis of geological criteria using the best data available at the time but, as further information becomes available, the original area of a field may need to be re-determined. A field can extend over more than one licence block, but can be determined only within licensed acreage.
1.11 The fiscal regime which currently applies to companies extracting oil and gas from the UK and the UKCS consists of three tiers:
1.12 The supplementary charge is calculated on the same basis as CT but without deduction for finance costs. PRT is a cash flow tax charged on the basis of individual oil and gas fields. RFCT is charged on CT profits at the level of the company's ring fence trade. Any royalty (abolished after 31 December 2002) plus any PRT paid by a company is deducted in computing its RFCT profits.
1.13 The regime, which applies to any particular oil field, depends on the date on which it received development consent:
1.14 Current marginal rates of tax are:
2.1 The main objectives behind PRT when it was introduced in 1975 were to:
2.2 PRT is a field-based tax. This means that, in general terms, the costs of developing one field cannot be set against the profits from another field (but see Chapter 4 for exceptions to this rule). Losses can, however, be carried forwards or backwards indefinitely. Subject to the availability of various reliefs this secures payment of PRT from a field once it has reached profitability.
2.3 Fields are developed by the licence holders and so they are usually developed by a number of companies who work together in joint ventures. Occasionally a single company will be licensee and will develop the field alone.
2.4 Where several companies are working via a joint venture they will appoint one company as the field's 'operator'. The operator will organise all the major work but the other co-venturers will play an active part in all decisions and pay their share of all field-based costs incurred by the operator. For PRT purposes all the joint venture companies are known as 'participators'.
2.5 For the purposes of administering PRT one company (almost always the operator) is appointed as the 'responsible person' (see Chapter 5).
2.6 PRT is assessed on each participator in each field. Assessments are raised for six-month chargeable periods ending on 30 June and 31 December in each year.
2.7 In essence the assessments are made up from incomings (known in the legislation as 'positive amounts') and expenditure (known as 'negative amounts'). In addition, various reliefs are often available. Chapter 3 gives some details on the incomings and Chapter 4 deals with expenditure and other reliefs. Chapter 5 outlines the administrative procedures involved.
2.8 As noted in Chapter 1, PRT was abolished for all fields given development consent on or after 16 March 1993. The fields that are within the charge to PRT are known as 'taxable', those outside it are known as 'non-taxable'. Many taxable fields do not pay PRT because of the various reliefs available.
3.1 Incomings (positive amounts) for PRT purposes include three main items: the gross profit arising from disposals of oil and gas produced by each participator in each chargeable period (known as equity), tariff receipts (consideration received in return for use of assets by, or provision of services to, participators in other fields) and disposal receipts (consideration received from disposal of certain assets).
3.2 The PRT gross profit is itself made up of several elements, the main ones being:
Royalty and RFCT are charged on the prices and market values agreed for PRT purposes of oil and gas disposed of by each participator.
3.3 It should be noted that the PRT charge relating to an arms' length sales arises when the oil is delivered, not when payment is received by the seller. If there is a delay in payment, the tax charge is still raised on the amount receivable rather than the amount received.
3.4 Where a sale is at arm's length, PRT is charged on the contract price and the legislation sets out certain conditions which a sale must satisfy if it is to be accepted as arm's length for PRT purposes. Very broadly speaking, the legislation defines an arm's length sale as one in which the contract is for a cash sale between unconnected parties without any other complexities. In practice, as the oil markets have developed with increasingly complex transactions and trading instruments, commercial sales between both connected and unconnected parties can fail to satisfy the statutory definition of arm's length.
3.5 Sales which do not satisfy the statutory definition of arm's length together with disposals which are not sales eg transfers between group companies, oil taken by the participator for refining, commodity swaps etc., are charged to PRT at market value. The legislation sets out how market value for PRT purposes is to be computed.
3.6 For crude oil, the legislation requires a market value to be computed for each day in each chargeable period. The statutory market value for a particular day is then applied to all non-arm's length disposals on that day, regardless of the actual sale price.
3.7 The statutory market value computation changed significantly for disposals after 30 June 2006, when the valuation calculations were altered from monthly values to daily values based upon commercial Price Reporting Agency price assessments, applied to a 'Notional Delivery Date'. There are anti-avoidance rules to address potential manipulation of Notional Delivery Dates.
3.8 Market values are computed for each of the crude oil grades produced in the North Sea (Brent, Forties, etc.) and so reflect the different prices achieved in the open market for each type of oil.
3.9 The original legislation for taxing disposals of light gases had been designed to deal with a stable market mainly comprised of gas sold under long term contracts to British Gas. In the early 1990s, developing competition in the UK market for light gases prompted the introduction of new valuation rules for this product. The new rules, which were enacted in 1994, were intended to provide the flexibility to recognise the different circumstances arising in the changing market or which might arise as the market developed further.
3.10 For any sale of light gases which is not at arm's length, the new legislation requires that a hypothetical or 'notional' contract is constructed between the seller and the buyer, by reference to arm's length contracts struck in similar circumstances. The aim is thus to mirror the actual arm's length market in this product in order to find a price for the non-arm's length disposal.
3.11 Each component of the contract is valued (length of supply, location, volume) in order to arrive at a price which reflects all the circumstances of the disposal. If the price derived from the notional contract falls within the range seen in comparable arm's length contracts then it is acceptable for PRT purposes.
3.12 Valuation of light gases is developing as the emerging UK markets for this product expand and change.
3.13 In addition to crude oil and light gases, which form the bulk of production, natural gas liquids such as butane, propane and ethane are produced in the North Sea. Non-arm's length disposals of these products are taxed at the statutory market value, in a similar fashion to crude oil and light gases.
3.14 In general, the market values of natural gas liquids (LPG’s and Condensates) are derived from an arithmetic average of prices in arm's length contracts for sale of these products.
3.15 In 1987 an anti-avoidance measure was introduced called the 'nomination scheme'. The scheme was aimed at combating manipulation of the oil prices returned for PRT purposes by companies taking advantage of the very liquid and at times volatile spot market in North Sea crudes to match low-priced contracts with oil produced from their field interests and to satisfy high-priced contracts with bought-in oil.
3.16 This works by reducing the amount of hindsight that companies enjoyed to pick and choose which contracts were set against their own oil. The nomination scheme requires a producer to 'nominate' that a particular forward contract will be used to deliver crude oil in the future, within two hours of the deal being struck.
3.17 Disposals which are nominated correctly are subject to PRT on the actual price achieved under the sale contract. Disposals which are not nominated according to the regulations are taxed at the higher of the statutory market value for the Notional Delivery Date or the price received under the contract.
3.18 In 2006 rules were introduced to prevent field entitlement volumes allocated to a single cargo being manipulated between taxable and non-taxable fields to take advantage of changes to the price of crude oil, by attributing oil to fields based upon a company’s estimated field volume entitlement.
3.18 The PRT legislation excludes sales proceeds from any gas sold to British Gas under contracts made before 30 June 1975 from the computation of gross profit.
3.19 The purpose of this exemption was to recognise that, prior to the introduction of PRT, gas from a number of fields had been sold to the former British Gas Corporation under contracts which lasted for the life of the field and which were not high enough to justify a PRT charge on the producer.
3.20 Amendments to such exempt contracts take place from time to time but when the relationship between seller and buyer remains substantially governed by the terms of the original contract, the exempt status is not affected. If cumulative amendments resulted in a fundamental alteration to the original agreement, the exemption from the charge to PRT would be lost.
3.21 Oil companies that own assets used by other oil fields receive payments (known as 'tariffs') from other oil companies in respect of the use of those assets. Typical examples are the transportation and initial processing of oil. Tariffs may also be paid for the provision of other services, such as the provision of electrical power, and these are also within the charge to PRT.
3.22 When PRT was introduced tariffs were not within the charge to PRT. But with tariffing becoming increasingly common, tariffs were brought within PRT by the Oil Taxation Act 1983. An allowance, known as tariff receipts allowance, is available to set against tariff income. See 4.20 et. seq.
3.23 To help achieve optimum use of existing North Sea infrastructure and the development of all commercially viable reserves, as of 1 January 2004 PRT was removed from all new third party tariffing business. This exemption applies to contracts entered into on or after 9 April 2003, relating to use of infrastructure in the UK and on the UKCS, where services are provided to new fields given development consent on or after 9 April 2003, or where the user field has never used PRT-liable infrastructure before (other than infrastructure within the field itself).
3.24 Assets that have been given relief for PRT purposes are sometimes disposed of. The consideration received is brought within the charge to PRT by section 7 of the Oil Taxation Act 1983.
4.1 As noted in Chapter 2, PRT is a field-based tax and, in general, it is only expenditure incurred on an oil field that can be set against the income from that field. Most expenditure incurred by oil companies working on the UKCS is related to particular oil fields, particularly to their development and operation, and is covered at 4.5 to 4.11.
4.2 Other reliefs (oil allowance and safeguard) are also available on a-field basis (see 4.12 to 4.19 below), as is tariff receipts allowance (see 4.20 to 4.23 below).
4.3 Broadly speaking, where an interest in a field changes hands, the new owner inherits the position of the old owner, including any unused expenditure relief and allowable losses, and also the 'cumulative capital expenditure' for safeguard. The transferor and transferee can jointly elect for these provisions not to be applied. Such an election can only be refused if it would have a material effect on the tax chargeable in the field in question.
4.4 Cross-field reliefs are covered at 4.24 et seq. below.
4.5 The rules allowing field-related expenditure for PRT purposes do not distinguish capital from revenue and almost all expenditure qualifies for 100 per cent relief as it is incurred. The legislation does, however, distinguish expenditure on long-term assets (defined as assets expected to be used after the end of the claim period in which it was first used for the field) from other expenditure. This is particularly important where an asset is used by more than one oil field.
4.6 Relief is available for expenditure incurred for one or more of the following field purposes:
4.7 Relief is also available for the cost of acquiring and operating tariff-generating assets.
4.8 Some expenditure is specifically prohibited as being allowed for PRT. This includes:
4.9 Because interest and loan costs are not allowable for PRT, these costs are reflected in a relief known as 'supplement' (often referred to as 'uplift', which is an addition of 35 per cent to, broadly, certain capital expenditure).
4.10 In order to qualify for supplement the expenditure must have been incurred for specific purposes, including bringing a field on-stream and substantially improving the rate of production or transportation.
4.11 This additional relief is available for expenditure incurred up to the end of the period in which the cumulative field cash flow first turns positive (the 'net profit period', often referred to as 'payback'). This can involve expenditure incurred well into the production phase.
4.12 The intention behind the introduction of oil allowance in the Oil Taxation Act 1975 was to protect the economics of small or marginal fields. Oil allowance, which gives a PRT-free 'first slice' of production to each field, is given after all expenditure relief and losses, but only so far as to reduce the profit for the period to nil.
4.13 The allowance is given by converting a defined amount of oil or gas into cash by way of a statutory formula.
There are three levels of oil allowance:
The value is given by the formula A x B/C, where:
A = the participator's gross profit
B = the participator's share of the oil allowance for the period
C = his share of the oil produced from the field in the period
The allowance of 125,000, 250,000 or 500,000 mt is shared between the participators in accordance with their share of the oil produced.
4.14 There is a cumulative limit over the life of the field of 20 times the allowance per period. Therefore oil allowance is available for a minimum of ten years, but it can be available for longer if the full amount is not used in each chargeable period.
4.15 Oil allowance is given to each participator for each chargeable period, after all other reliefs (except safeguard), have been taken into account. Any balance of allowance in terms of volume which is not utilised in a chargeable period is carried forward as part of the pool of oil allowance, but it does not increase the allowance for a later period above the normal limit per period.
4.16 Safeguard is designed to give companies a degree of assurance about the minimum level of profits they can expect to enjoy after PRT (but before CT), with a view to ensuring that marginal fields remain profitable. It does this by restricting the amount of PRT payable by a participator in a chargeable period if the effect of the PRT would be to reduce after-tax profit below a minimum return on investment in the field. Safeguard is only available for a limited number of periods being half the number of periods from commencement to payback – see 4.11 above.
4.17 First, PRT is calculated in the normal way, after all allowances and reliefs including oil allowance. Second, the 'adjusted profit' is determined. This is assessable profit (before any reduction for losses or oil allowance) for the period, with any expenditure qualifying for supplement, the supplement itself and any cross-field reliefs added back.
4.18 If the adjusted profit is less than 15 per cent of the participator's 'accumulated capital expenditure' in the field up to the end of the chargeable period in question, the PRT for that chargeable period is reduced to nil. The 'accumulated capital expenditure' is defined as the cumulative amount of field expenditure allowed as qualifying for supplement.
4.19 If the adjusted profit is more than 15 per cent of accumulated capital expenditure the PRT charge is the lesser of:
4.20 The Tariff Receipts Allowance (TRA), introduced at the same time as the charge on tariffs, is a relief against tariff income received from taxable fields or foreign fields in return for the use of assets used for the extraction, transportation, initial treatment or initial storage of oil.
4.21 TRA was introduced to offset the impact it was felt a full PRT charge would have had on tariff levels, which in turn would have had a detrimental effect on the economics of marginal user fields.
4.22 TRA is calculated by reference to a formula according to which relief is given on the cash equivalent of an amount of throughput to which the tariffs relate. The amount of TRA is given by the formula A x B/C, where:
A = participator's qualifying tariff receipts
B = TRA for the field in mt
C = total throughput to which the tariffs relate in mt
Broadly speaking, the throughput is the mass of oil that is, say, transported by the host field on behalf of the user field.
4.23 The allowance ('B' above) is currently up to 250,000 mt of oil per user field per chargeable period. Any unused allowance cannot be transferred or carried forward or back.
4.24 As mentioned above, most allowable expenditure is incurred in relation to developing and operating oil fields, but significant amounts of expenditure are incurred elsewhere. A number of reliefs are available in respect of this expenditure. Because these reliefs, which are outlined in more detail below, temper the field-based nature of PRT they are often referred to as 'cross-field' reliefs - of which the cross-field allowance is just one example
4.25 When the original Oil Taxation Act was enacted in 1975, cross-field relief for exploration expenditure was available only where the expenditure had proved abortive. That is, companies had to show it was not, and was unlikely to become, allowable as a field-related expense. The allowable expenditure will include such things as the cost of seismic surveys and their interpretation, drilling wells and well testing.
4.26 No expenditure incurred after 15 March 1983 qualifies for this relief. Despite its abolition, some abortive expenditure relief remains to be claimed by companies who have not yet reached a position where they have had enough profits chargeable to PRT to utilise all the relief they have available.
4.27 Following the 1983 Finance Act, cross-field relief was widened to include all exploration and appraisal expenditure on the UKCS (even if it was successful). Eligible expenditure includes the costs of searching for oil and gas, for ascertaining the extent, characteristics or reserves of any oil or gas bearing area.
4.28 Where the expenditure relates to an area that becomes an oil field, the relief is only available in respect of expenditure incurred prior to consent being granted by DBERR for development of the area as a field.
4.29 This relief enables a participator to get 100 per cent PRT relief for exploration and appraisal expenditure against the income of any field in which the participator has an interest. The relief may be claimed at any time, thus enabling it to be set against the income from fields that are paying PRT, or would do so but for the relief.
4.30 This relief relates to expenditure incurred after 15 March 1983 and before 16 March 1993 and was the most important cross-field relief prior to its abolition. The 1993 Finance Act also provided for some transitional relief for expenditure after 15 March 1993 and before 16 March 1995. As is the case with abortive expenditure relief, significant amounts of exploration and appraisal relief remain to be claimed by companies who have not yet reached a position where they have had enough profits chargeable to PRT to utilise all the relief they have available.
4.31 Oil companies carry out research on a wide range of oil-related matters. Much of this research might be applicable to many or all of the fields in which the companies participate. As such, it is not related to a specific field and fails to qualify for in-field relief under the normal PRT rules.
4.32 The 1987 Finance Act introduced a cross-field relief for research expenditure, enabling companies to claim relief on research costs that do not relate to a particular oil field but do have a UK purpose. 'Research' is not defined, but for it to be allowable cross-field there is a requirement for it to be allowable under the normal rules of PRT if the research had been field-related.
4.33 Research relief is the only cross-field relief available for expenditure incurred otherwise than for a field purpose on or after 16 March 1993 (subject only to the transitional exploration and appraisal relief ).
4.34 If an oil field is unsuccessful, the expenditure and associated supplement might be greater than its income over the life of the field. In such a case there will be an excess of expenditure which cannot be relieved within the field. The excess, referred to as unrelievable field losses, is available to set against income from other fields.
4.35 A participator can elect to surrender up to 10 per cent of certain expenditure incurred in developing certain new fields and set it against his PRT profits in another field, thereby getting immediate tax-effective relief for the expenditure concerned.
4.36 The expenditure that qualifies for this relief is, broadly, expenditure which qualifies for supplement in the field for which it was incurred. Expenditure that is transferred as a CFA is left out of account in the field of origin. In return for getting immediate relief, the participator loses any entitlement to supplement on the transferred expenditure. But as the donor fields are often small and not expected to pay PRT the supplement would be worthless in terms of tax relief.
4.37 The relief is restricted to qualifying expenditure in offshore fields outside the Southern Basin for which development consent was given on or after 17 March 1987. CFA is not available on expenditure incurred on fields given development consent on or after 16 March 1993. It follows that the amount of expenditure qualifying for CFA is dwindling and the relief will, in time, disappear.
5.1 In Chapter 2 it was explained that assessments to PRT are raised on field participators for six-month chargeable periods.
5.2 The responsible person for each taxable field has to submit a return of the total amount of oil and gas produced from the field within one month of the end of each chargeable period. This gives details of each participator's percentage interest in the field and the amount of each participator's share of the total oil produced.
5.3 Each participator has to submit a return of their own incomings from each taxable field in which they have an interest two months after the end of each chargeable period. An additional return that provides details of all other arm's length sales and purchases of crude oil is also required from each participator to enable computation of the statutory market value.
5.4 Before any expenditure is allowed in an assessment it has to be claimed and allowed by the LBSOG. The vast majority of expenditure is incurred and claimed by the responsible person on behalf of the participators. The claim shows how the expenditure should be shared between the participators.
5.5 Some expenditure is incurred by the participators and is claimed by them on their own account.
5.6 Expenditure allowed by the LBSOG is given as relief in the assessment next made after the expenditure is allowed.
5.7 Assessments are usually raised five months after the end of each chargeable period.
5.8 A payment on account is due at the time of the submission of each chargeable period's return, two months after the end of the period (ie on 31 August and 28 February). This payment on account is based on a type of self-assessment for the period, including the gross revenues, valuations and royalties shown in the return, expenditure incurred and claimed (with appropriate supplement) whether or not so far allowed, allowances (such as oil allowance and safeguard) and losses.
5.9 Since the end of 1983 the bulk of PRT has been collected in six equal monthly instalments (each equal to one eighth of the payment on account for the previous chargeable period), starting two months after the beginning of the period. The instalments are credited against the payment on account due two months after the end of the period.
5.10 PRT assessments are normally issued on 31 May and 30 November each year (or the previous last working day). Payment of any further PRT is then due within six months after the end of the relevant chargeable period (or thirty days after the assessment is issued, if later). If the amount of the payment on account is greater than the assessed PRT, the excess is repaid.
5.11 Interest on overdue instalments is payable from the date on which payment was due. Interest on overdue PRT not payable by instalments is payable from two months after the end of the relevant chargeable period, as is interest due to the taxpayer on tax overpaid. Interest paid or received is not deductible or chargeable for PRT or corporation tax purposes. The interest rate is variable by Treasury Order.
Example: period ended 30 June 2008
Assume payment on account relating to the period ended 31 December 2007 and made on 28 February 2008 was £40 million.
First instalment due 28 February 2008
2nd-6th instalments due 31 March to 31 July 2008
Company's estimate of PRT liability for period
Payment on account 31 August 2008 (50 - 30)
Assessment raised 30 November 2008 with PRT liability
Further PRT due 31 December 2008
If the company's estimate of the liability for the period had been £25 million, a repayment of £5 million would have been made shortly after 31 August 2008.
If the assessment had shown PRT liability of £47 million, £3 million would have been repaid during December 2008.
6.1 All the standard corporation tax provisions apply to oil companies operating in the UK. However, there is in addition a ring fence around North Sea profits. The basic premise of the ring fence is that corporation tax on profits from oil extraction activities should be paid in full as the profits accrue, undiluted by any losses or any other form of relief arising from any other business activities whether in the UK or elsewhere. The ring fence imposes restrictions to achieve this.
6.2 Firstly, oil extraction activities are treated as a separate (ring fence) trade, distinct from all other activities carried out by the company or group of companies. Oil extraction activities ('oil' for these purposes includes gas) are defined as activities, in the UK or a designated area (ie the UKCS), in searching for oil, extracting oil, transporting oil to dry land in the UK or effecting initial treatment or initial storage of oil. Profits from these activities are usually referred to as 'ring fence' profits.
6.3 Normally a company may set trading losses against any other income, including the profits of a different trade. The ring fence prohibits the use of such losses against the profits from oil extraction. A similar rule prevents capital losses arising from the disposal of business assets outside the ring fence trade from being set against chargeable gains accruing within the ring fence. Likewise, no amounts may be surrendered as group relief to a company to be set off against ring fence profits, unless the relief itself originates from losses incurred by an associated company in an oil extraction activity.
6.4 Losses from oil extraction may be carried forward or back against the profits of that trade. The ring fence only works in one direction and so there is nothing to prevent ring fence corporation tax losses being set against non-extraction activities of a company or group of companies.
6.5 Secondly, relief for interest payments can only be set against ring fence profits to the extent that the interest was paid in respect of money borrowed to finance genuine oil extraction activities.
6.6 Thirdly, a company could not set off any Advance Corporation Tax (ACT) against its mainstream corporation tax on its ring fence profits, if that ACT arose on a distribution made to an associated company that is resident in the UK. Neither could ACT on such a distribution be surrendered to be set off against any ring fence profits of a subsidiary. Without this restriction, the company receiving the dividend might have generated a surplus of franked investment income against which it could relieve its non-ring fence trading losses. These rules and others relating to ACT have been repealed following the abolition of ACT from 6 April 1999.
6.7 Fourthly, any ring fence transactions within a single company are treated as if they were transactions between associates. The normal transfer pricing rules are also suspended where the trade involves the disposal or appropriation of oil. Instead the PRT valuation rules are brought into play for corporation tax purposes.
6.8 Any PRT paid by a company is an allowable deduction against ring fence profits.
6.9 In common with other activities, capital expenditure on oil extraction activities in the North Sea can normally only be relieved under the appropriate Capital Allowances codes. From 17 April 2002 an enhanced first year capital allowance is available for almost all ring fence capital expenditure.
6.10 The normal rules apply in the North Sea for allowances in respect of expenditure on the provision of plant and machinery for the purposes of the trade (where the expenditure does not fall within any of the categories below). Relief is available on a 25 per cent writing down allowance basis for expenditure incurred before 17 April 2002. From that date expenditure (other than that on long-life assets) qualifies for an immediate 100 per cent allowance Given the long term nature of projects in the North Sea and the scale of the assets involved, the provisions in the capital allowances legislation relating to long life assets (with a useful life of over 25 years) are sometimes applied to expenditure on the UKCS. This restricts the rate at which allowances can be claimed to, currently, 6 per cent per annum for expenditure incurred before 17 April 2002. From that date expenditure qualifies for a 24 per cent first year allowance and 6 per cent writing down allowance thereafter.
6.11 The capital cost of oil exploration and appraisal activity may be relieved in full in the year it is incurred under the Research and Development (R&D) capital allowances code.
6.12 Expenditure on mineral exploration and access incurred before 17 April 2002 will normally qualify for Mineral Extraction Allowance (MEA) on a 25 per cent writing down allowance basis unless it qualifies under the R&D code. Expenditure incurred on or after 17 April 2002 qualifies for a 100 per cent first year allowance. Expenditure on acquiring mineral rights or deposits will also qualify for MEA but at the lower rate (currently 10 per cent).
6.13 The normal rules apply.
6.14 Expenditure on the abandonment of fields which is capital in nature will also normally qualify for relief within the Capital Allowances code. A special 100 per cent capital allowance is available for these costs, and any loss attributable to such may be carried back against profits for up to three years, in contrast to the usual one year carry back.
7.1 The Supplementary Charge (SC) in respect of ring fence trades was introduced in the Finance Act 2002 and applies to the profits of companies producing oil or gas in the UK or on the UKCS. It applies only to oil and gas production; it does not apply to contractors working in the UK or on the UKCS.
7.2 Companies pay a supplementary charge of 20 per cent on profits from their UK and UKCS oil and gas production, in addition to the current 30 per cent corporation tax on these 'ring fence' profits.
7.3 The SC is calculated on virtually the same basis as ring fence corporation tax, and administered in the same way as corporation tax. Companies pay the SC on ring fence profits at the same time as their general corporation tax liability, but special rules for instalment payments covered the transitional period (ie the accounting period that included the day of the announcement - 17 April 2002). These special rules ensured that no underpayment of instalments would arise by virtue of the introduction of the charge. There is also a first year allowance of 100 per cent for almost all ring fence capital expenditure. This means that 100 per cent of most North Sea capital expenditure is allowable for Corporation Tax, including the SC, in the year that the expenditure is incurred.
7.4 Although the profits base for the SC will be in most respects identical to that for general corporation tax, no deduction is allowed for companies' financing costs. This is to prevent companies manipulating their levels of borrowing between ring fence and non-ring fence activities to minimise the impact of the SC.
8.1 Ring fence Corporation Tax and Supplementary Charge are payable in three equal instalments on 14 July, 14 October and 14 January each year.
Email: PRT, CT
HM Revenue & Customs
Large Business service: Oil & Gas Sector
Tel: 020 7438 6576
Fax: 020 7438 9195
North Sea Tax Policy
Oil and Gas Directorate
Department of Business, Enterprise & Regulatory Reform (BERR)
1 Victoria Street
Tel: 020 7215 5271
Fax: 020 7215 5228
Petroleum Exploration and Production Licences
Oil and Gas Directorate
Department of Business, Enterprise & Regulatory Reform (BERR)
1 Victoria Street
Tel: 020 7215 5121
Fax: 020 7215 5142