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HMRC internal manual

Oil Taxation Manual

From
HM Revenue & Customs
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Field allowance: definition of a qualifying field

Ultra high pressure/high temperature field

Up to and including 23 July 2010 an ultra high pressure/high temperature (HP/HT) field is a field with oil at a pressure of more than 1034 bar and a temperature of more than 176.67 Celsius in the reservoir formation. From 24 July 2010 the figures are 862 bar and 166 Celsius respectively.

The figures for pressure and temperature will be taken by DECC/HMRC as those in the reservoir formation (ie at the hydrocarbon-water contact) as reported in the first development programme approved for the field; any anomalous single well readings are to be disregarded and any necessary calculations are to have been agreed with DECC and applied. If the hydrocarbon-water contact has not been found and cannot be justifiably extrapolated, maximum pressure and temperature are to be taken and agreed with DECC from observations made at the depth of the deepest known hydrocarbons.

Ultra heavy oil field

An ultra heavy oil field is a field with oil at API gravity below 18 degrees and viscosity of more than 50 centipoise at reservoir temperature and pressure. For this purpose the API gravity is given by the formula:

141.5/G - 131.5  

where G is the specific gravity of the oil at 15.56 Celsius.

The figures of API gravity and viscosity will be taken by DECC/HMRC as those reported in the first development programme approved for the field.

Small oil or gas field

Up to and including 20 March 2012, a small oil or gas field is a field with oil equivalent reserves of 3.5 million tonnes or less. This limit increased to 7 million tonnes for fields whose development was authorised for the first time on or after 21 March 2012.

The amount of reserves is to be determined on the authorisation day, and 1100 cubic metres of gas at a temperature of 15 Celsius and pressure of one atmosphere is counted as equivalent to one tonne of oil.

The amount of reserves will be taken by DECC/HMRC as the central estimate of recoverable reserves reported in the first development programme approved for the field.

Deep water gas field

A deep water gas field (from 5 March 2010) is a field for which:

  • gas is to be transported for more than 60 kilometres along a new pipeline to relevant infrastructure
  • the depth of the sea is more than 300 metres, and
  • more than 75% of the reserves comprise gas.

Relevant infrastructure is any pipeline or gas processing facility which is being used, or is planned for use, by another oil field whose authorisation of development is on a day preceding that of the deep water gas field. The length of the planned route for the primary pipeline(s) for transporting gas from the oil field to the relevant infrastructure is to be determined on the authorisation day.

The depth of the sea is to be measured at the lowest astronomical tide from the water surface to the lowest point of the natural seabed at the location of the deeper of the primary subsea manifold or the first development well.

The size of the reserves is to be determined on the authorisation day, and the equivalence between gas and oil is as for a small field.

Large deep water oil field

A large deep water oil field is a field

  • which was authorised for the first time on or after 21 March 2012
  • has reserves of oil of 25 million tonnes or more but less than 55 million tonnes, and
  • for which the depth of the sea above the field is more than 1000 metres.

The depth of the sea is to be measured as for a deep water gas field.

The amount of the reserves is to be determined on the authorisation day, and the equivalence between gas and oil is as for a small field.

Large shallow water gas field

A large shallow water gas field is a field

  • which was authorised for the first time on or after 25 July 2012
  • for which more than 95% of the reserves comprise gas
  • for which the depth of the sea above the field is less than 30 metres
  • for which the amount of reserves of gas which the field has (or where there are one or more fields related to the field, the total amount of reserves of gas which all the fields together have) is 10 billion cubic metres or more but less than 25 billion cubic metres.

A field is ‘related’ to another field if the field meets the first 3 conditions above and the authorisation day for each field is the same.

The amount of the reserves is to be determined on the authorisation day, and the equivalence between gas and oil is as for a small field.

The depth of the sea is to be measured at the lowest astronomical tide from the water surface to the highest point of the natural sea bed at the location of the primary subsea manifold or the first development well, whichever is the shallower.

The availability or amount of the field allowance depends on a field satisfying the qualifying criteria for the type of field concerned. Companies are advised to approach the Department of Energy and Climate Change (DECC) to seek their agreement to the figures being adopted, for example in respect of the figure of reserves for a small field, before submitting a tax return to HMRC showing a deduction for a field allowance.

Additionally-developed oil field

An incremental project qualifies for the allowance if it is a project

  • described in a Field Development Plan Addendum and which has been authorised by DECC on or after 7 September 2012,
  • where the cost of the project exceeds £60 per tonne of additional reserves,
  • where the additional reserves to be recovered as a result of the project have not been taken into consideration in calculating the cost per tonne of any previous project which attracted a field allowance,
  • where the whole of the field is offshore, and
  • where the project does not involve enhanced oil recovery using carbon dioxide.

The cost per tonne of the project is the amount of incremental capital expenditure which is expected to be incurred in carrying out the project, excluding sunk costs, decommissioning expenditure and interest payments. An amount for contingencies may be included on individual items where appropriate, but must not be greater than 20 per cent. The expected capital expenditure is determined on the day DECC authorises the Field Development Plan Addendum in which the project is described.

To calculate the cost per tonne of the project, 1,100 cubic metres of gas at a temperature of 15 Celsius and pressure of one atmosphere is considered equivalent to one tonne.

Additional reserves are the incremental reserves which are expected as a result of the project. The amount of additional reserves which a field has is determined on the day DECC authorises the Field Development Plan Addendum in which the project is described.