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Decommissioning provisions
The extractive industries, power generation and
other utilities create environmental change and
inflict damage in the ordinary course of business.
Entities are usually required to perform some kind
of decommissioning or environmental restoration
work at the end of the useful life of a plant or
other installation. There may also be environmental
clean up obligations arising from contamination
of land that arises during the operating life of
a refinery or other installation.
A provision is recognised when an obligation exists
to perform the clean up [IAS37R.14]. Obligations
to decommission or remove an asset are created at
the time the asset is put in place. An offshore
drilling platform, for example, must be removed
at the end of its useful life. However, the obligation
to remove arises from its placement. If its useful
life is 10,000 barrels or 1,000,000 the obligation
will not change in substance. Entities recognise
decommissioning provisions at the present value
of the expected future cash flows that will be required
to perform the decommissioning [IAS37R.45]. The cost of
the provision is recognised as part of the cost
of the asset when it is placed in service and depreciated
over the asset's useful life [IAS16R.16(c)]. The
total cost of the fixed asset, including the cost
of decommissioning, is depreciated on the basis
that best reflects the consumption of the economic
benefits of the asset; units of production in extractive
industries or time based for a power station.
Provisions for decommissioning and restoration
are recognised even if the decommissioning is not
expected to be performed for a long time, for example
80 to 100 years. The effect of the time to expected
decommissioning will be reflected in the discounting
of the provision.
Revisions to decommissioning provisions
The decommissioning provisions are updated at each
balance sheet date for changes in the estimates
of the future cash flows and changes in the discount
rate [IAS37R.59]. Changes to provisions that relate
to the removal of an asset are added to or deducted
from the carrying amount of the asset [IFRIC1.5].
The adjustments to the asset are restricted however.
The asset cannot decrease below zero and cannot
increase above recoverable amount [IFRIC1.5].
The accretion of the discount on a decommissioning
liability is recognised as part of finance expense
in the income statement.
First time adoption
and decommissioning provisions
There is a specific optional exemption
in IFRIC 1 that allows a short cut method for decommissioning
obligations at the date of first time adoption.
The company is allowed to calculate the liability
in accordance with IAS 37 as of the date of transition
(opening balance sheet date). The related asset
is calculated by estimating the amount that has
been added to the provision through accretion of
the discount. This estimated asset amount at initial
recognition is then depreciated to the date of transition
using the appropriate method.
Deferred tax on decommissioning
obligations
The amount of the asset and liability
recognised at initial recognition of decommissioning
or on subsequent revisions of estimates are generally
viewed as being within the scope of the current
'initial recognition exemption' in IAS 12 [IAS12R.15]
[IAS12R.24]. The asset and liability do not affect
accounting profit or taxable profit and so do not
attract deferred tax. The amount of accretion in
the provision from unwinding of the discount gives
rise to a book/tax difference and will result in
a deferred tax asset, subject to an assessment of
recoverability. IFRIC considered a similar question
at its April and June 2005 meetings of whether the
IAS 12 initial recognition exemption applied to
the recognition of finance leases. IFRIC acknowledged
that there was diversity in practice in the application
of the initial recognition exemption for finance
leases but decided not to issue an interpretation
because of the IASB's short-term convergence project
with the FASB. Accordingly some entities might take
an alternative view that the IAS 12 initial recognition
exemption should not be applied for finance leases
and decommissioning liabilities. However a consistent
policy should be adopted for deferred tax accounting
for decommissioning liabilities and finance leases
[IAS8R.13].
Provisions for emissions obligations
Many governments in Europe and elsewhere have introduced
cap and trade schemes as a way to encourage a reduction
in the emission of greenhouse gases. The schemes generally
involve the allocation of a limited number of allowances
at the start of a compliance period and the requirement
of emitters to hand back allowances to the government
at the end of the period equal to the volume of emissions
made.
The emission of greenhouse gases creates an obligation
to deliver allowances. Entities must recognise a
provision in respect of this obligation to the extent
of emissions made as at the balance sheet date [IAS37R.14].
At interim balance sheet dates it is not appropriate
to recognise the provision on the basis of expected
full year emissions - the obligation is only in
respect of actual emissions made to date.
The provision recognised is measured at the amount
that it is expected to cost the entity to settle
the obligation. Generally this will be the market
price at the balance sheet date of the allowances
required to cover the emissions made to date (the
full market value approach) [IAS37R.37]. An alternative
is to measure the obligation in two parts [IAS37R.36]:
| i) the obligation for which allowances are
already held by the entity - this may be measured
at the carrying amount of the allowances held;
and |
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| ii) the obligation for which allowances are
not held and must be purchased in the market
- this is measured at the current market price
of allowances. |
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Entities should make clear in their accounting
policy which approach they are following.
Entities using the alternative two-part approach
should measure the obligation for which allowances
are held by allocating the value of allowances to
the obligation on either a FIFO or weighted average
basis. Entities using this approach should only
recognise an obligation at the current market price
of allowances to the extent that emissions made
to date exceed the volume of allowances held. There
is no obligation to purchase additional allowances
if emissions do not exceed allowances and so no
basis to use the current market price.
The emissions allowances held are intangible assets
and guidance on the accounting for these is included
in chapter 128 Assets for energy and utilities .
Accounting for petroleum taxes
Petroleum taxes generally fall into two categories
- those that are calculated on profits earned (income
taxes) and those calculated on production or sales
(royalty or excise taxes). The categorisation is
crucial: royalty and excise taxes do not form part
of revenue while income taxes usually require deferred
tax accounting but form part of revenue. This section
addresses both types of tax.
Petroleum taxes - royalty and excise
Petroleum taxes that are calculated by applying
a tax rate to a calculation of revenue or volume
do not fall within the scope of IAS 12 and are not
income taxes. They do not form part of revenue and
a liability for revenue-based and volume-based taxes
is recognised when the production occurs or revenue
arises [IAS18R.8]. These taxes are most often described
as royalty or excise taxes. They are measured in
accordance with the relevant tax legislation and
a liability is recorded for amounts collected or
due that have not yet been paid to the government.
No deferred tax is calculated. The smoothing of
the estimated total tax charge over the life of
a field is not appropriate [IAS37R.15] [IAS37R.36].
Royalty and excise taxes are in effect the government's
share of the natural resources exploited and are
a share of production free of cost. They may be
paid in cash or in kind. If in cash, the entity
sells the oil or gas and remits to the government
its share of the proceeds. Royalty payments in cash
or in kind are excluded from gross revenues and
costs .
Petroleum taxes based on profits
Petroleum taxes that are calculated by applying
a tax rate to a measure of profit fall within the
scope of IAS 12 [IAS12R.5]. The profit measure used
to calculate the tax is that required by the tax
legislation and will, accordingly, differ from the
IFRS profit measure. Profit in this context is revenue
less costs but is not, for example, an allocation
of profit oil in a PSC. Examples include Petroleum
Revenue Tax in the UK and Norwegian Petroleum Tax
.
Petroleum taxes on income are often 'super' taxes
applied in addition to ordinary corporate income
taxes. The tax may apply only to profits arising
from specific geological areas or sometimes on a
field by field basis within larger areas. The petroleum
tax may or may not be deductible when determining
corporate income tax; this does not change its character
as a tax on income. The computation of the tax is
often complicated. There may be a certain number
of barrels or bcm that are free of tax, accelerated
depreciation and additional tax credits for investment.
Often there is a minimum tax computation as well.
Each complicating factor in the computation must
be separately evaluated and accounted for in accordance
with IAS 12 .
Deferred tax must be calculated in respect of all
taxes which fall within the scope of IAS 12 [IAS12R.15]
[IAS12R.24]. The deferred tax is calculated separately
for each tax by identifying the temporary differences
between the IFRS carrying amount and the corresponding
tax base for each tax. Petroleum income taxes may
be assessed on a field specific basis or a regional
basis. An IFRS balance sheet and a tax balance sheet
will be required for each area or field subject
to separate taxation.
The tax rate applied to the temporary differences
will be the statutory rate. The statutory rate may
be adjusted for certain allowances and reliefs in
certain limited circumstances where the tax is calculated
on a field-specific basis without the opportunity
to transfer profits or losses between fields [IAS12R.47]
[IAS12R.51] .
Taxes in PSCs
Production sharing contracts are discussed in further
detail in Chapter 126 The reporting group for energy
and utilities . However, a crucial question arises
as to the taxation of PSCs - when are amounts paid
to the government an income tax (and thus form part
of revenue) and when are amounts a royalty and excluded
from revenue. Some PSCs include a requirement for
the national oil company or another government body
to pay income tax on behalf of the operator of the
PSC. When does tax paid on behalf of an operator
form part of revenue and income tax expense?
The revenue arrangements and tax arrangements are
unique in each country and can vary within a country,
such that each major PSC is usually unique. However,
there are common features that will drive the assessment
as income tax, royalty or government share of production.
Before a company can classify as tax any payments
to the government or by the government on behalf
of the operator, all of the following criteria must
be met:
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the country must have a robust income tax regime; |
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the PSC must specifically state that the company is subject to income tax; |
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the PSC should be transparent that tax paid on behalf of the company or by the company is income tax, |
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the company must prepare a tax return that shows the amounts as revenue, costs, profit and income tax expense, |
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the company must be legally liable
for income taxes until relieved of that obligation
by payment itself or by a third party; |
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deferred tax assets and liabilities will arise from the income tax; and |
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the tax must be based on a measure of profits . |
Tax paid in cash or in kind
Tax is usually paid in cash to the relevant tax
authorities. However, some governments allow payment
of tax through the delivery of oil instead of cash
for income taxes, royalty and excise taxes and amounts
due under licences, production sharing contracts
and the like.
The accounting for the tax charge and the settlement
through oil should reflect the substance of the
arrangement. Determining the accounting is straight
forward if it is an income tax (see definition above)
and is calculated in monetary terms. The volume
of oil used to settle the liability is then determined
by reference to the market price of oil. The entity
has in effect 'sold' the oil and used the proceeds
to settle its tax liability. These amounts are appropriately
included in gross revenue and tax expense.
Arrangements where the liability is calculated
by reference to the volume of oil produced without
reference to market prices can make it more difficult
to identify the appropriate accounting. These are
most often a royalty or volume based tax. The accounting
should reflect the substance of the agreement with
the government. Some arrangements will be a royalty
fee, some will be a traditional profit tax, some
will be an appropriation of profits and some will
be a combination of these and more. The agreement
or legislation under which oil is delivered to a
government must be reviewed to determine the substance
and hence the appropriate accounting. Different
agreements with the same government must each be
reviewed as the substance of the arrangement and
hence the accounting may differ from one to another.
Tax 'paid on behalf' (POB)
POB arrangements are varied but generally a government
entity will pay the income tax due by a foreign
upstream entity to government on behalf of the foreign
upstream entity. This occurs where the upstream
entity is the operator of fields under a PSC and
the government entity is usually the national oil
company that holds the government's interest in
the PSC. The crucial issue in accounting for tax
POB arrangements are if they is akin to a tax holiday
or if the upstream entity retains an obligation
for the income tax.
POB arrangements that represent a tax holiday such
that the upstream company has no legal tax obligation
are accounted for as a tax holiday. The upstream
company presents no tax expense and does not gross
up revenue for the tax paid on its behalf by the
government entity (see discussion of income tax
classification above).
Accruals and contingent liabilities
The accruals and other liabilities that an entity
recognises should reflect all that it has incurred
in respect of its own activities and those it has
incurred on behalf of other joint venture partners
[IAS31R.21]. Liabilities incurred by an entity in
its role as operator in a joint venture should be
recognised in full and separately from the amounts
recoverable from the other joint venture partners
[IAS1R.32].
Contingent liabilities should be described and
disclosed [IAS37R.86]. This should include those
liabilities and contingent liabilities of joint
venture partners for which the entity is contingently
liable [IAS31R.54].
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