BP » Topics » Oil and natural gas accounting

This excerpt taken from the BP 20-F filed Jun 13, 2006.

Oil and natural gas accounting

        Accounting for oil and gas exploration activity is subject to special accounting rules that are unique to the oil and gas industry. In the UK, these are contained in the Statement of Recommended Practice (SORP) 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'.

        The Group follows the successful efforts method of accounting for its oil and natural gas exploration and production activities.

        The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs.

        Licence and property acquisition costs are initially capitalized as unproved properties within intangible assets. These costs are amortized on a straight-line basis until such time as either exploration drilling is determined to be successful or it is unsuccessful and all costs are written off. Each property is reviewed on an annual basis to confirm that drilling activity is planned and it is not impaired. If no future activity is planned the remaining balance of the licence and property acquisition costs is written off.

        For exploration wells and exploratory-type stratigraphic test wells, costs directly associated with the drilling of wells are temporarily capitalized within intangible fixed assets, pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. The determination is usually made within one year after well completion, but can take longer, depending on the complexity of the geologic structure. If the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploration wells that discover potentially economic quantities of oil and gas and are in areas where major capital expenditure (e.g. offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration appraisal work is under way or firmly planned.

107



        For complicated offshore exploration discoveries, it is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and gas field is performed or while the optimum development plans and timing are established. All such carried costs are subject to regular technical, commercial and management review, on at least an annual basis, to confirm the continued intent to develop, or otherwise extract value from, the discovery. If this is no longer the case, the costs are immediately expensed.

        Once a project is sanctioned for development, the carrying values of licence and property acquisition costs and exploration and appraisal costs are transferred to production assets within tangible assets.

        Field development costs subject to depreciation are expenditures incurred to date together with sanctioned future development expenditure approved by the Group.

        The capitalized exploration and development costs for proved oil and gas properties (which include the costs of drilling unsuccessful wells) are amortized on the basis of oil-equivalent barrels that are produced in a period as a percentage of the estimated proved reserves. The estimated proved reserves used in these unit-of-production calculations vary with the nature of the capitalized expenditure. The reserves used in the calculation of the unit-of-production amortization are as follows:

    (a)
    Proved developed reserves for producing wells.

    (b)
    Total proved reserves for development costs.

    (c)
    Total proved reserves for licence and property acquisition costs.

    (d)
    Total proved reserves for future decommissioning costs.

        The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining book value of the asset over the expected future production. If proved reserve estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the property's book value (see discussion of impairment of fixed assets and goodwill below).

        Given the large number of producing fields in the Group's portfolio, it is unlikely that any changes in reserve estimates, year on year, will have a significant effect on prospective charges for depreciation.

        US GAAP requires the unit-of-production depreciation rate to be calculated on the basis of development expenditure incurred to date and proved developed reserves. If production commences before all development wells are drilled, a portion of the development costs incurred to date should be excluded from the unit-of production depreciation rate. In respect of the Group's portfolio of fields there is no material difference between the Group's charge for depreciation determined on a UK GAAP basis and on a US GAAP basis.

This excerpt taken from the BP 20-F filed Jun 30, 2005.

Oil and natural gas accounting

        Accounting for oil and gas exploration activity is subject to special accounting rules that are unique to the oil and gas industry. In the UK, these are contained in the Statement of Recommended Practice (SORP) 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'.

        The Group follows the successful efforts method of accounting for its oil and natural gas exploration and production activities.

        The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs.

        Licence and property acquisition costs are initially capitalized as unproved properties within intangible assets. These costs are amortized on a straight-line basis until such time as either exploration drilling is determined to be successful or it is unsuccessful and all costs are written off. Each property is reviewed on an annual basis to confirm that drilling activity is planned and it is not impaired. If no future activity is planned the remaining balance of the licence and property acquisition costs is written off.

        For exploration wells and exploratory-type stratigraphic test wells, costs directly associated with the drilling of wells are temporarily capitalized within intangible fixed assets, pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. The determination is usually made within one year after well completion, but can take longer, depending on the complexity of the geologic structure. If the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploration wells that discover potentially economic quantities of oil and gas and are in areas where major capital expenditure (e.g. offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration appraisal work is under way or firmly planned.

101



        For complicated offshore exploration discoveries, it is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and gas field is performed or while the optimum development plans and timing are established. All such carried costs are subject to regular technical, commercial and management review, on at least an annual basis, to confirm the continued intent to develop, or otherwise extract value from, the discovery. If this is no longer the case, the costs are immediately expensed.

        Once a project is sanctioned for development, the carrying values of licence and property acquisition costs and exploration and appraisal costs are transferred to production assets within tangible assets.

        Field development costs subject to depreciation are expenditures incurred to date together with sanctioned future development expenditure approved by the Group.

        The capitalized exploration and development costs for proved oil and gas properties (which include the costs of drilling unsuccessful wells) are amortized on the basis of oil-equivalent barrels that are produced in a period as a percentage of the estimated proved reserves. The estimated proved reserves used in these unit-of-production calculations vary with the nature of the capitalized expenditure. The reserves used in the calculation of the unit-of-production amortization are as follows:

    (a)
    Proved developed reserves for producing wells.

    (b)
    Total proved reserves for development costs.

    (c)
    Total proved reserves for licence and property acquisition costs.

    (d)
    Total proved reserves for future decommissioning costs.

        The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining book value of the asset over the expected future production. If proved reserve estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the property's book value (see discussion of impairment of fixed assets and goodwill below).

        Given the large number of producing fields in the Group's portfolio, it is unlikely that any changes in reserve estimates, year on year, will have a significant effect on prospective charges for depreciation.

        US GAAP requires the unit-of-production depreciation rate to be calculated on the basis of development expenditure incurred to date and proved developed reserves. If production commences before all development wells are drilled, a portion of the development costs incurred to date should be excluded from the unit-of production depreciation rate. In respect of the Group's portfolio of fields there is no material difference between the Group's charge for depreciation determined on a UK GAAP basis and on a US GAAP basis.

EXCERPTS ON THIS PAGE:

20-F
Jun 13, 2006
20-F
Jun 30, 2005
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