BP 2009 Annual Report Download - page 97

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BP Annual Report and Accounts 2009
Additional information for shareholders
Additional information for shareholders
Determination as to whether and how much an asset is impaired
involves management estimates on highly uncertain matters such as
future commodity prices, the effects of inflation on operating expenses,
discount rates, production profiles and the outlook for global or regional
market supply-and-demand conditions for crude oil, natural gas and
refined products.
For oil and natural gas properties, the expected future cash flows
are estimated based on the group’s plans to continue to develop and
produce proved reserves and associated risk-adjusted probable and
possible volumes. Expected future cash flows from the sale or
production of these volumes are calculated based on the management’s
best estimate of future oil and natural gas prices. Prices for oil and
natural gas used for future cash flow calculations are based on market
prices for the first five years and the group’s long-term planning
assumptions thereafter. As at 31 December 2009, the group’s long-term
planning assumptions were $75 per barrel for Brent and $7.50/mmBtu
for Henry Hub (2008 $75 per barrel and $7.50/mmBtu). These long-term
planning assumptions are subject to periodic review and modification.
The estimated future level of production is based on assumptions about
future commodity prices, lifting and development costs, field decline
rates, market demand and supply, economic regulatory climates and
other factors.
The future cash flows are adjusted for risks specific to the cash-
generating unit and are discounted using a pre-tax discount rate. The
discount rate is derived from the group’s post-tax weighted average cost
of capital and is adjusted where applicable to take into account any
specific risks relating to the country where the cash-generating unit is
located, although other rates may be used if appropriate to the specific
circumstances. In 2009 the rates ranged from 9% to 13% (2008 11%
to 13%). The rate applied in each country is re-assessed each year by
analysing relevant information.
Irrespective of whether there is any indication of impairment,
BP is required to test annually for impairment of goodwill acquired in a
business combination. The group carries goodwill of approximately
$8.6 billion on its balance sheet (2008 $9.9 billion), principally relating
to the Atlantic Richfield and Burmah Castrol acquisitions. In testing
goodwill for impairment, the group uses a similar approach to that
described above. If there are low oil prices or natural gas prices or
refining margins or marketing margins for an extended period, the group
may need to recognize significant goodwill impairment charges. In 2009,
an impairment loss of $1.6 billion was recognized to write off all of the
goodwill allocated to the US West Coast fuels value chain. The prevailing
weak refining environment, together with a review of future margin
expectations in the FVC, led to a reduction in the expected future
cash flows.
Taxation
The computation of the group’s income tax expense involves the
interpretation of applicable tax laws and regulations in many jurisdictions
throughout the world. The resolution of tax positions taken by the group,
through negotiations with relevant tax authorities or through litigation,
can take several years to complete and in some cases it is difficult to
predict the ultimate outcome.
In addition, the group has carry-forward tax losses in certain
taxing jurisdictions that are available to offset against future taxable
profit. However, deferred tax assets are recognized only to the extent
that it is probable that taxable profit will be available against which the
unused tax losses can be utilized. Management judgement is exercised
in assessing whether this is the case.
To the extent that actual outcomes differ from management’s
estimates, taxation charges or credits may arise in future periods. For
more information see Financial statements – Note 16 on page 137 and
Note 41 on page 176.
Derivative financial instruments
The group uses derivative financial instruments to manage certain
exposures to fluctuations in foreign currency exchange rates, interest
rates and commodity prices as well as for trading purposes. In addition,
derivatives embedded within other financial instruments or other host
contracts are treated as separate derivatives when their risks and
characteristics are not closely related to those of the host contract.
All such derivatives are initially recognized at fair value on the date on
which a derivative contract is entered into and are subsequently
remeasured at fair value. Gains and losses arising from changes in the
fair value of derivatives that are not designated as effective hedging
instruments are recognized in the income statement.
In some cases the fair values of derivatives are estimated using
models and other valuation methods due to the absence of quoted prices
or other observable, market-corroborated data. In particular, this applies to
the majority of the group’s natural gas embedded derivatives. These are
primarily long-term UK gas contracts that use pricing formulas not related
to gas prices, for example, oil product and power prices. These contracts
are valued using models with inputs that include price curves for each of
the different products that are built up from active market pricing data and
extrapolated to the expiry of the contracts using the maximum available
external pricing information. Additionally, where limited data exists for
certain products, prices are interpolated using historic and long-term
pricing relationships. Price volatility is also an input for the models.
Changes in the key assumptions could have a material impact on the
gains and losses on embedded derivatives recognized in the income
statement. For more information see Financial statements – Note 31 on
page 152. An analysis of the sensitivity of the fair value of the embedded
derivatives to changes in the key assumptions is provided in Financial
statements – Note 24 on page 144.
Provisions and contingencies
The group holds provisions for the future decommissioning of oil and
natural gas production facilities and pipelines at the end of their
economic lives. The largest asset removal obligations facing BP relate to
the removal and disposal of oil and natural gas platforms and pipelines
around the world. The estimated discounted costs of dismantling and
removing these facilities are accrued on the installation of those
facilities, reflecting our legal obligations at that time. A corresponding
asset of an amount equivalent to the provision is also created within
property, plant and equipment. This asset is depreciated over the
expected life of the production facility or pipeline. Most of these removal
events are many years in the future and the precise requirements that
will have to be met when the removal event actually occurs are
uncertain. Asset removal technologies and costs are constantly
changing, as well as political, environmental, safety and public
expectations. Consequently, the timing and amounts of future cash
flows are subject to significant uncertainty. Changes in the expected
future costs are reflected in both the provision and the asset.
Decommissioning provisions associated with downstream and
petrochemicals facilities are generally not provided for, as such potential
obligations cannot be measured, given their indeterminate settlement
dates. The group performs periodic reviews of its downstream and
petrochemicals long-lived assets for any changes in facts and
circumstances that might require the recognition of a decommissioning
provision.
The timing and amount of future expenditures are reviewed
annually, together with the interest rate used in discounting the cash
flows. The interest rate used to determine the balance sheet obligation
at the end of 2009 was 1.75% (2008 2%). The interest rate represents
the real rate (i.e. excluding the impacts of inflation) on long-dated
government bonds.