27 Sep 2010

United Kingdom Oil and Gas Taxation

This is an archived version of the legislation. For an up-to-date summary please go to our Reference Page.

SUMMARY

Companies undertaking oil and gas exploration, development and production activities in the UK are subject to three tiers of direct taxation in the UK; petroleum revenue tax (PRT), corporation tax (CT) and supplementary charge (SC).  PRT (at 50%) is deductible against corporation tax and supplementary charge.  Corporation tax is currently chargeable at 30% on these activities and supplementary charge is levied at 32% in respect of profits accruing after 23 March 2011 (previously 20%). The profit base for SCT is the CT profit base as adjusted for financing items.

For activities subject to PRT the maximum marginal rate is 81% (with the CT and SC effect), although the effective rate of tax can exceed this  where companies are highly geared due to the lack of a deduction for interest costs for PRT and supplementary charge.

PETROLEUM REVENUE TAX (PRT)

Petroleum Revenue Tax, which is currently charged at 50%, was introduced in 1975.  It is levied on a field by field basis by reference to six-monthly chargeable periods ending 30 June and 31 December.

PRT has been abolished for all fields for which development consent was granted on or after 15 March 1993 but continues to apply to older fields.

Gas sold to British Gas under contracts signed before 1 July 1975 and oil appropriated for field production is exempts.

PRT is payable on the value of oil and gas produced less allowable costs and reliefs.

Each field is a separate taxable unit. So each licensee must produce a separate return for each field in which it has an interest, and the return will include only income and expenses for that field. There are, however, a number of non-field reliefs available.

PRT is also payable on certain tariff receipts and disposal receipts on assets whose cost has qualified for PRT relief.

To determine the value of oil and gas sold, there is a distinction between arm-length and non-arm’s length sales.  For arm’s length sales the actual sales proceeds are used.  For non-arm’s length disposals or appropriations (other than for production purposes) the market value, as determined by LBS Oil &Gas, is brought in. A ‘nominations’ system determines whether an arm’s length valuation may be used for arms length sales which are delivered into certain types of forward contract. If a sale is within the nomination scheme but is not correctly nominated it will be taxed on the higher of the LBS Oil & Gas market value for the delivery month and actual realisation.

Tariff receipts are chargeable to PRT insofar as they relate to the use of, or services provided in connection with the use of, a qualifying asset or related facilities.  “Qualifying assets” are those expenditure on which has attracted actual or deemed PRT relief, except for non-dedicated mobile assets.  Any proceeds from the disposal of a qualifying asset are also brought into charge.  An exception to this rule is that tariffs from fields receiving development consent after April 8th 2003 or fields that have not used other fields’ infrastructure before that date are exempt if the tariff agreement was entered into after April 8th 2003.

Taxable tariff receipts in respect of extraction, transport, initial treatment, or initial storage of oil won otherwise than from the principal field attract a throughput allowance where the “user” field is also a taxable field i.e. a field determined before March 16th 1993.  Tariffs earned in respect of the first 250,000 tonnes of throughput per chargeable period from each taxable user field are effectively exempt from charge.  The allowance cannot create a loss.

PRT is also extended to charge tariff and disposal receipts earned by licensees in non UK fields to the extent that the tariff or disposal receipts relate to assets situated on the UK continental shelf and those assets are used by UK fields.

PRT cost allowances essentially give relief in full for outlays as incurred, regardless of whether the expenditure is of a ‘revenue’ or ‘capital’ nature.  Claimed expenditure is only deductible against income once it has been determined as allowable by LBS Oil & Gas.  The reliefs can be summarised as follows:

Field expenditure

Most costs of exploring, appraising, developing, producing, measuring and selling oil won, and abandoning a field will be qualifying costs for relief.  In respect of exploration costs, relief is given if the “searching” cost is incurred within 5,000 metres of the field boundary notwithstanding the costs may not be related to that field.

Relief is given in full in the first relevant period other than for expenditure incurred on non-dedicated mobile assets or expenditure on remote associated assets.  A mobile asset is dedicated to a field if it is expected that it will be used in that field for substantially the whole of the asset’s remaining life.  If the asset is non-dedicated, relief is only available for that part of the expenditure which relates to periods of use.

Remote associated assets are those put in place purely to earn tariff income, any part of which is situated more than 100 metres from a main field asset, e.g. a spur pipeline.  Relief for the cost of such assets is only available against the tariff income (net of TRA) earned from that asset.

A supplementary allowance (uplift) is given at 35% on certain, broadly capital, expenditure, including the majority of costs incurred in bringing the field into production plus any costs incurred after first oil in substantially improving the rate at which oil can be won from the field.  However, uplift only applies to qualifying expenditure incurred prior to payback i.e. when cumulative income exceeds cumulative expenditure plus uplift.

The main non-deductible items for PRT are: financing costs, e.g. interest; the cost of acquiring land or interests in land; certain buildings, e.g. administrative offices; de-ballasting; expenditure that depends on the results of the field, e.g. a royalty interest; payments to obtain interests in oil, e.g. licence acquisitions from other licensees; expenditure met by subsidy.

To the extent expenditures (plus uplift) in any chargeable period exceed income the resultant loss can be carried forward or back indefinitely.

Where costs are incurred partly for a qualifying field purpose and partly for another purpose then an apportionment must be made.  To the extent that costs are incurred to generate a taxable tariff this is treated as a qualifying PRT purpose.  Costs associated with generating non-taxable tariffs are not allowable.  In this case HMRC generally operate a “safe-harbour” approach whereby the cost disallowance is restricted to 50% of the tariff.

 

Non-field reliefs

Although the taxable unit is the field, certain expenditures incurred otherwise than in respect of that field are nevertheless allowable.

 

Cross-field allowance

This is available for expenditure in offshore taxable fields outside the Southern Basin where development consent was given after March 16, 1987.  Up to 10% of qualifying expenditure (basically that which would qualify for uplift – see above) incurred after that date may be set against PRT profits from another field in the same group.  However, uplift is foregone on the expenditure claimed.

 

Research expenditure relief

Research costs that do not become allowable with respect to a specific field within three years of being incurred but which have an application to taxable fields may be set against the participator’s PRT profits from any field (but not those of an affiliate).

 

Abandoned field loss relief

If, following the cessation of production from a field, there is a cumulative loss (ignoring any oil allowance relief (see below)), that loss may be claimed against the PRT profits of any other field in the same group ownership.

Other reliefs

 

Oil allowance

This permits a maximum of 250,000 tonnes per field per chargeable period to be free of PRT, with an aggregate relief of 5 million tonnes available.  This allowance was doubled for fields obtaining development approval after 31 March 1982, but is halved for fields onshore or in the Southern basin.  This allowance is shared among the participators in the field.  It can only reduce a profit to zero and cannot create a loss.

 

Safeguard

This relief is aimed at providing a normal rate of return against PRT.  It limits the PRT payable to a maximum of 80% of the amount by which the “adjusted profit” (broadly PRT profit from the field before deducting expenditure qualifying for supplement, and non-field reliefs) exceeds 15% of the accumulated capital expenditure at the end of each period.  The accumulated capital expenditure is the cumulative expenditure for the field that has qualified for supplement.  Safeguard applies to all chargeable periods until payback and, thereafter, for half as many periods again.

 

Payment of PRT

The rules require payments on account and instalment payments.  Estimated PRT liabilities are payable on account two months after the end of the chargeable period, and adjustments dealt with on formal assessment.  There is also a system of monthly instalment payments based on prior period liabilities, whereby 1/8 of the previous period’s liability is due at the end of the second month of the chargeable period, and at the end of each of the next five months.

 

CORPORATION TAX

Corporation tax is levied on a company by company basis, rather than the field basis of PRT.  A company with more than one field interest will therefore aggregate the results for those fields in arriving at its profits subject to corporation tax.

Taxable profits for corporation tax are determined by adjusting normal accounting profits; in particular, depreciation is disallowed and relief for capital expenditure given through specific capital allowances.  PRT is deductible for corporation tax purposes.

For “large” companies corporation tax is payable in instalments. The current rate of 30% is applied for ‘ring fence’ profits, and the tax is due on these profits in three quarterly instalments where the return covers the normal 12 month period. The first instalment is due six months and 14 days into the period and the others follow quarterly thereafter. This contrasts with the four instalments and a lower rate in respect of non ‘ring fence’ profits.

 

The Ring Fence

While all companies operating in the UK are within the corporation tax regime there are some additional rules (the ring fence rules) that relate to upstream oil and gas activities.  These ring fence rules are designed to prevent companies reducing their upstream ring fence profits with reliefs and allowances from other activities.

The main restrictions are that losses and expenses from other activities, either within the company or accruing to an affiliate, cannot be deducted against ring fence profits.  The deductibility of financing costs is also limited such that, broadly, interest deductions are only available in respect of monies borrowed which have been used in the ring fence business, and where the terms do not exceed those applicable at arm’s length. In applying the rules, the assumption is made that the ring fence business is supported solely by the ring fence assets of the borrower.  There are restrictions on the utilisation of capital losses against capital gains, and limitations on the amount of capital allowances that can be claimed on field transfers.

Other than the above the normal corporation rules are applied to the ring fence activities. There are however a number of areas of the regime that are of particular relevance to upstream activities, which are set out below.

 

Capital Allowances

Neither capital expenditure nor the depreciation of those costs is allowable for corporation tax purposes, instead there are specific capital allowances available which are deducted from chargeable profits.

The allowances that are of most relevance to upstream activities are research and development allowances (RDAs), plant and machinery allowances (P&M), and mineral extraction allowances (MEAs).  No allowances are available until a company commences to trade, but once it does all capital costs incurred prior to commencement are deemed to have been incurred at commencement.

 

RDAs

RDAs, for which relief at 100% is given, apply to all exploration and appraisal costs until such time as reserves in commercial quantities have been discovered.  The costs must be first hand exploration or appraisal costs.  No relief under these provisions is therefore available for reimbursing previously qualifying costs or when buying into a licence (but see comments on MEAs below).

 

P&M

The capital cost of production and transportation facilities will generally qualify for plant and machinery capital allowances.  Most costs incurred after April 16th 2002 will qualify for immediate 100% relief, although prior to that date costs only qualified at the rate of 25% per annum on a reducing balance basis.  Expenditure on ‘long life assets’, i.e. those with a useful economic life that is expected to be 25 years or more, incurred after April 16th 2002 and before 1 April 2008 only qualify for an initial 24% allowance with the balance, and any previously incurred costs, qualifying for relief at the rate of 10% per annum on a reducing balance basis from 1 April 2008 (previously 6%).  From 1 April 2008 a 100% FYA is available in respect of expenditure on new long life assets used within the ring fence.  All qualifying assets (other than long life assets) are put into a single main pool or a special rate pool with a balancing allowance or charge arising when the last such asset in that category is disposed of, being the difference between the disposal proceeds and the balance of unclaimed allowances at that time.  If the assets are acquired as part of a Schedule 17 FA80 field transfer any claim is restricted to the cost of the seller.

 

MEAs

Mineral extraction allowances (MEAs) are available for mineral exploration and access expenditures (broadly all expenditures up to first production from a source) and on acquiring a mineral asset, but the rates differ between the types of expenditure.  Costs incurred on acquiring a mineral asset, and which cannot be attributed to past mineral extraction and access expenditure, qualify for a 10% writing down allowance on a reducing basis. But mineral exploration and access expenditure in a ring fence trade incurred after April 16th 2002 qualifies for an immediate 100% first year allowance.  Costs incurred prior to that, other than on acquiring a mineral asset, qualified for writing-down allowances at 25% per annum on a reducing balance basis.  In practice most costs potentially falling under this category will qualify for research and development allowance and will normally be claimed as such, unless the company doesn’t need the relief immediately, but for development drilling costs that do not qualify for RDAs can usually be claimed under the MEA code.  So-called “second-hand” exploration costs (e.g. reimbursements), and any value representing past exploration expenditure on licence acquisitions, qualify for the 100% relief (or 25% for expenditure prior to April 17th 2002) in a ring fence trade.

 

Decommissioning

Special rules apply to decommissioning expenditure.  Costs relating to the demolition of offshore installations and pipelines may qualify for a 100% deduction in the period they are incurred, but for other costs the relief may vary. Finance Act 2012 contained changes designed to restrict the rate at which relief for CT and SC is given for abandonment expenditures to 50%.

The costs of obtaining an abandonment guarantee are expressly allowable where they qualify as deductible for PRT and from 2013 it is expected this treatment will be explicitly allowed even where there is no application of PRT.

Losses

Trading losses may be carried forward indefinitely and set against future profits of the same trade.  Losses may generally be carried back 1 year.  To the extent the loss is generated by decommissioning expenditure there is 3 year carry back against total profits and thereafter a carry back (to April 2002) against ring fence profits.

Ring Fence Expenditure Supplement.

For accounting periods ended after 1 January 2006 Ring Fence Expenditure Supplement (RFES) may be available where a company makes a loss.

The RFES allow companies to claim a 6% supplement on a company’s ring fence trading loss for 6, not necessarily consecutive, periods. It applies to losses accruing in periods commencing on or after 1st January 2006. The rate of supplement was increased to 10% for accounting periods commencing on or after 1 January 2012. Losses attributable to exploration and appraisal expenditures incurred under the old Exploration Expenditure Supplement rules can also be taken into account.  Losses are computed on the assumption that all other available reliefs, such as group relief and loss carry back against ring fence profits, are claimed.

SUPPLEMENTARY CHARGE

A supplementary charge (SC) applies to ring fence profits accruing from April 17th 2002.  The rate was originally 10%, increased to 20% in 2006 and to 32% in respect of profits accruing after 23 March 2011.  The tax base is the ring fence profits of the company chargeable to CT after removing all financing costs.  Supplementary charge is payable in instalments as with CT.

FIELD ALLOWANCES

The original field allowance was introduced in Finance Act 2009, with further allowances following. The allowance reduces the profits of a company subject to the supplementary charge once the relevant field starts producing. It applies to fields which received development consent after 22 April 2009.  The allowance available, if any, depends upon meeting certain field criteria as at the date that development consent was granted (or in the case of the Brown Field relief, at the time of the addendum to the development consent)  .

There are currently 8 different levels of field allowances available where the gross level of allowance varies from £75m to £3bn. They are

Post 22 April 2009 Small Field Allowance

Post 21 March 2012 Small Filed Allowance

Ultra Heavy Oil Field Allowance

Ultra High Pressure High Temperature Allowance Field Allowance

Deep Water Gas Field Allowance

Sizeable Reserves Field Allowance

Shallow Gas Field Allowance

Brown Field Allowance

These allowances are shared between holders of the relevant fields and the relief available may be tapered where the field in question does not fully meet the necessary criteria.

 

CW Energy LLP – January 2013