BP 2007 Annual Report Download - page 59

BP ANNUAL REPORT AND ACCOUNTS 2007 57
Critical accounting policies
The significant accounting policies of the group are summarized in
Financial statements – Note 1 on page 100.
Inherent in the application of many of the accounting policies used in
preparing the financial statements is the need for BP management to
make estimates and assumptions that affect the reported amounts of
assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period.
Actual outcomes could differ from the estimates and assumptions used.
The following summary provides further information about the critical
accounting policies that could have a significant impact on the results of
the group and should be read in conjunction with the Notes on financial
statements.
The accounting policies and areas that require the most significant
judgements and estimates used in the preparation of the consolidated
financial statements are in relation to oil and natural gas accounting,
including the estimation of reserves, the recoverability of asset carrying
values, deferred taxation, provisions and contingencies, and pensions and
other post-retirement benefits.
Oil and natural gas accounting
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.
Licence and property acquisition costs are initially capitalized within
intangible assets. These costs are amortized on a straight-line basis until
such time that a determination is made on whether exploratory drilling
activity is successful. Where a determination is made that the exploratory
drilling is unsuccessful all costs are written off. Each property is reviewed
on an annual basis to confirm that drilling activity is planned and that 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 non-current intangible 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
geological 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 on 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.
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. Where
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 property, plant and
equipment. Field development costs subject to depreciation are
expenditures incurred to date, together with approved future
development expenditure required to develop reserves.
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:
– Producing wells – proved developed reserves.
– Licence and property acquisition, field development and future
decommissioning costs – total proved reserves.
The impact of changes in estimated proved reserves is dealt with
prospectively by amortizing the remaining carrying value of the asset
over the expected future production. If proved reserves estimates are
revised downwards, earnings could be affected by higher depreciation
expense or an immediate write-down of the property’s carrying value
(see discussion of recoverability of asset carrying values below).
Given the large number of producing fields in the group’s portfolio, it is
unlikely that any changes in reserves estimates for individual fields, either
individually or in aggregate, year on year, will have a significant effect on
the group’s prospective charges for depreciation.
At the end of 2006, BP adopted the SEC rules for estimating reserves
instead of the UK accounting rules contained in the UK Statement of
Recommended Practice. These changes are explained in Financial
statements – Note 9 on page 120.
The estimation of oil and natural gas reserves and BP’s process to
manage reserves bookings is described in Exploration and Production –
Reserves and production on page 15. As discussed below, oil and natural
gas reserves have a direct impact on the assessment of the
recoverability of asset carrying values reported in the financial
statements.
The 2007 movements in proved reserves are reflected in the tables
showing movements in oil and gas reserves by region in Financial
statements – Supplementary information on oil and natural gas on pages
177 to 185.
Recoverability of asset carrying values
BP assesses its fixed assets, including goodwill, for possible impairment
if there are events or changes in circumstances that indicate that carrying
values of the assets may not be recoverable and, as a result, charges for
impairment are recognized in the group’s results from time to time. Such
indicators include changes in the group’s business plans, changes in
commodity prices leading to unprofitable performance, low plant
utilization and, for oil and gas properties, significant downward revisions
of estimated volumes or increases in estimated future development
expenditure. If there are low oil prices, natural gas prices, refining
margins or marketing margins during an extended period, the group may
need to recognize significant impairment charges.
The assessment for impairment entails comparing the carrying value
of the cash-generating unit and associated goodwill with the recoverable
amount of the asset, that is, the higher of fair value less costs to sell and
value in use. Value in use is usually determined on the basis of
discounted estimated future net cash flows.
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 group’s best
estimate of future oil and 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 2007, the group’s long-term planning assumptions were
$60 per barrel for Brent and $7.50 per mmBtu for Henry Hub (2006 $40