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1 Significant accounting policies continued
Licence and property acquisition costs
Exploration and property leasehold acquisition costs are capitalized within intangible fixed assets and amortized on a straight-line basis over the estimated period of exploration. 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. Upon determination of economically recoverable reserves (‘proved reserves’ or ‘commercial reserves’), amortization ceases and the remaining costs are aggregated with exploration expenditure and held on a field-by-field basis as proved properties awaiting approval within other intangible assets. When development is approved internally, the relevant expenditure is transferred to property, plant and equipment.
Exploration expenditure
Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. If hydrocarbons are not found, the exploration expenditure is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, which may include the drilling of further wells (exploration or exploratory-type stratigraphic test wells), are likely to be capable of commercial development, the costs continue to be carried as an asset. All such carried costs are subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to property, plant and equipment.
Development expenditure
Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalized within property, plant and equipment.
Property, plant and equipment
Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of any decommissioning obligation, if any, and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalized value of a finance lease is also included within property, plant and equipment.
Exchanges of assets are measured at the fair value of the asset given up unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized. Inspection costs associated with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance programmes are expensed as incurred. All other maintenance costs are expensed as incurred.
Oil and natural gas properties, including related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, decommissioning and field development costs are amortized over total proved reserves. The unit-of-production rate for the amortization of field development costs takes into account expenditures incurred to date, together with sanctioned future development expenditure.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life.
The useful lives of the group’s other property, plant and equipment are as follows:
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| Land improvements | 15 to 25 years |
| Buildings | 20 to 40 years |
| Refineries | 20 to 30 years |
| Petrochemicals plants | 20 to 30 years |
| Pipelines | 10 to 50 years |
| Service stations | 15 years |
| Office equipment | 3 to 7 years |
| Fixtures and fittings | 5 to 15 years |
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The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
The carrying value of property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable.
An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period the item is derecognized.
Impairment of intangible assets and property, plant and equipment
The group assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If any such indication of impairment exists, the group makes an estimate of its recoverable amount. An asset group’s recoverable amount is the higher of its fair value less costs to sell and its value in use. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money.
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1 Significant accounting policies continued
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in profit or loss. After such a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Financial assets
Financial assets are classified as loans and receivables; available-for-sale financial assets; financial assets at fair value through profit or loss; or as derivatives designated as hedging instruments in an effective hedge, as appropriate. Financial assets include cash and cash equivalents; trade receivables; other receivables; loans; other investments; and derivative financial instruments. The group determines the classification of its financial assets at initial recognition. When financial assets are recognized initially, they are measured at fair value, normally being the transaction price plus, in the case financial assets not at fair value through profit or loss, directly attributable transaction costs. As explained in Note 49, the group has not restated comparative amounts on first applying IAS 32 and IAS 39, as permitted in IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’.
The subsequent measurement of financial assets depends on their classification, as follows:
Loans and receivables
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process.
Available-for-sale financial assets
Available-for-sale financial assets are those non-derivative financial assets that are not classified as loans and receivables. After initial recognition, available-for-sale financial assets are measured at fair value, with gains or losses being recognized as a separate component of equity until the investment is derecognized or until the investment is determined to be impaired, at which time the cumulative gain or loss previously reported in equity is included in the income statement.
The fair value of quoted investments is determined by reference to bid prices at the close of business on the balance sheet date. Where there is no active market, fair value is determined using valuation techniques. These include using recent arm’s-length market transactions; reference to the current market value of another instrument which is substantially the same; discounted cash flow analysis; and pricing models. Where fair value cannot be reliably estimated, assets are carried at cost.
Financial assets at fair value through profit or loss
Derivatives, other than those designated as hedging instruments, are classified as held for trading and are included in this category. These assets are carried on the balance sheet at fair value with gains or losses recognized in the income statement.
Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value, the treatment of gains and losses arising from revaluation are described below in the accounting policy for Derivative financial instruments.
Impairment of financial assets
The group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired.
Loans and receivables
If there is objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is reduced, with the amount of the loss recognized in administration costs.
Available-for-sale financial assets
If an available-for-sale financial asset is impaired, an amount comprising the difference between its cost (net of any principal payment and amortization) and its fair value is transferred from equity to the income statement.
If there is objective evidence that an impairment loss on an unquoted equity instrument that is not carried at fair value because its fair value cannot be reliably measured, or on a derivative asset that is linked to and must be settled by delivery of such an unquoted equity instrument, has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the current market rate of return for a similar financial asset.
Financial assets are derecognized on sale or settlement.
Inventories
Inventories, other than inventory held for trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.
Inventories held for trading purposes are stated at fair value less costs to sell and any changes in net realizable value are recognized in the income statement.
Supplies are valued at cost to the group mainly using the average method or net realizable value, whichever is the lower.
Trade and other receivables
Trade and other receivables are carried at the original invoice amount, less allowances made for doubtful receivables. Where the time value of money is material, receivables are carried at amortized cost. Provision is made when there is objective evidence that the group will be unable to recover balances in full. Balances are written off when the probability of recovery is assessed as being remote.
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1 Significant accounting policiescontinued
Cash and cash equivalents
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; and short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.
For the purpose of the group cash flow statement, cash and cash equivalents consist of cash and cash equivalents as defined above, net of outstanding bank overdrafts.
Trade and other payables
Trade and other payables are carried at payment or settlement amounts. Where the time value of money is material, payables are carried at amortized cost.
Interest-bearing loans and borrowings
All loans and borrowings are initially recognized at fair value, being the fair value of the proceeds received net of issue costs associated with the borrowing.
After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs, and any discount or premium on settlement.
Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized respectively in interest and other revenues and other finance expense.
Leases
Finance leases, which transfer to the group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between the finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are charged directly against income.
Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term.
Operating lease payments are recognized as an expense in the income statement on a straight-line basis over the lease term.
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. From 1 January 2005, such derivative financial instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.
Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments, as if the contracts were financial instruments, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group’s expected purchase, sale or usage requirements, are accounted for as financial instruments.
For those derivatives designated as hedges and for which hedge accounting is desired, the hedging relationship is documented at its inception. This documentation identifies the hedging instrument, the hedged item or transaction, the nature of the risk being hedged and how effectiveness will be measured throughout its duration. Such hedges are expected at inception to be highly effective.
For the purpose of hedge accounting, hedges are classified as |
| – | Fair value hedges when hedging the exposure to changes in the fair value of a recognized asset or liability. |
| – | Cash flow hedges when hedging exposure to variability in cash flows that is either attributable to a particular risk associated with a recognized assetor liability or a highly probable forecast transaction, including intragroup transactions. |
| – | Hedges of the net investment in a foreign entity. |
Any gains or losses arising from changes in the fair value of all other derivatives, which are classified as held for trading, are taken to the income statement. These may arise from derivatives for which hedge accounting is not applied because they are either not designated or not effective as hedging instruments or from derivatives that are acquired for trading purposes.
The treatment of gains and losses arising from revaluing derivatives designated as hedging instruments depends on the nature of the hedging relationship, as follows: |
Fair value hedges
For fair value hedges, the carrying amount of the hedged item is adjusted for gains and losses attributable to the risk being hedged; the derivative is remeasured at fair value and gains and losses from both are taken to profit or loss. For hedged items carried at amortized cost, the adjustment is amortized through the income statement such that it is fully amortized by maturity. When an unrecognized firm commitment is designated as a hedged item, this gives rise to an asset or liability in the balance sheet, representing the cumulative change in the fair value of the firm commitment attributable to the hedged risk.
The group discontinues fair value hedge accounting if the hedging instrument expires or is sold, terminated or exercised, the hedge no longer meets the criteria for hedge accounting or the group revokes the designation.
Cash flow hedges
For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognized directly in equity, while the ineffective portion is recognized in profit or loss. Amounts taken to equity are transferred to the income statement when the hedged transaction affects profit or loss. Where the hedged item is the cost of a non-financial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the non-financial asset or liability.
If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked, amounts previously recognized in equity remain in equity until the forecast transaction occurs and are transferred to the income statement or to the initial carrying amount of a non-financial asset or liability as above. If a forecast transaction is no longer expected to occur, amounts previously recognized in equity are transferred to profit or loss.
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1 Significant accounting policiescontinued
Hedges of the net investment in a foreign entity
For hedges of the net investment in a foreign entity, the effective portion of the gain or loss on the hedging instrument is recognized directly in equity, while the ineffective portion is recognized in profit or loss. Amounts taken to equity are transferred to the income statement when the foreign entity is sold.
Embedded derivatives
Derivatives embedded in 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. Contracts are assessed for embedded derivatives when the group becomes a party to them, including at the date of a business combination. Embedded derivatives are measured at fair value at each balance sheet date. Any gains or losses arising from changes in fair value are taken directly to profit or loss.
Provisions and contingencies
Provisions are recognized when the group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the group expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognized as a separate asset, but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as other finance expense. Any change in the amount recognized for environmental and litigation and other provisions arising through changes in discount rates is included within other finance expense.
A contingent liability is disclosed where the existence of an obligation will only be confirmed by future events or where the amount of the obligation cannot be measured with reasonable reliability. Contingent assets are not recognized, but are disclosed where an inflow of economic benefits is probable.
Environmental expenditures and liabilities
Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future earnings are expensed.
Liabilities for environmental costs are recognized when environmental assessments or clean-ups are probable and the associated costs can be reasonably estimated. Generally, the timing of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.
The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. Where an obligation exists for a new facility, such as oil and natural gas production or transportation facilities, this will be on construction or installation. An obligation for decommissioning may also crystallize during the period of operation of a facility through a change in legislation or through a decision to terminate operations. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements.
A corresponding item of property, plant and equipment of an amount equivalent to the provision is also created. This is subsequently depreciated as part of the capital costs of the facility or item of plant.
Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment.
Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the period end are valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The accounting policy for pensions and other post-retirement benefits is described below.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted and is recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award. Fair value is determined by using an appropriate valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions).
No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which are treated as vesting irrespective of whether or not the market condition is satisfied, provided that all other performance conditions are satisfied.
At each balance sheet date before vesting, the cumulative expense is calculated, representing the extent to which the vesting period has expired and management’s best estimate of the achievement or otherwise of non-market conditions and the number of equity instruments that will ultimately vest or, in the case of an instrument subject to a market condition, be treated as vesting as described above. The movement in cumulative expense since the previous balance sheet date is recognized in the income statement, with a corresponding entry in equity.
Where the terms of an equity-settled award are modified or a new award is designated as replacing a cancelled or settled award, the cost based on the original award terms continues to be recognized over the original vesting period. In addition, an expense is recognized over the remainder of the new vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of the modified award, both as measured on the date of the modification. No reduction is recognized if this difference is negative.
Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation and any cost not yet recognized in the income statement for the award is expensed immediately. Any compensation paid up to the fair value of the award at the cancellation or settlement date is deducted from equity, with any excess over fair value being treated as an expense in the income statement.
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1 Significant accounting policiescontinued
Cash-settled transactions
The cost of cash-settled transactions is measured at fair value using an appropriate option valuation model. Fair value is established initially at the grant date and at each balance sheet date thereafter until the awards are settled. During the vesting period, a liability is recognized representing the product of the fair value of the award and the portion of the vesting period expired as at the balance sheet date. From the end of the vesting period until settlement, the liability represents the full fair value of the award as at the balance sheet date. Changes in the carrying amount for the liability are recognized in profit or loss for the period.
Pensions and other post-retirement benefits
The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period (to determine current service cost) and to the current and prior periods (to determine the present value of defined benefit obligation) and is based on actuarial advice. Past service costs are recognized immediately when the company becomes committed to a change in pension plan design. When a settlement (eliminating all obligations for benefits already accrued) or a curtailment (reducing future obligations as a result of a material reduction in the scheme membership or a reduction in future entitlement) occurs, the obligation and related plan assets are remeasured using current actuarial assumptions and the resultant gain or loss is recognized in the income statement during the period in which the settlement or curtailment occurs.
The interest element of the defined benefit cost represents the change in present value of scheme obligations resulting from the passage of time, and is determined by applying the discount rate to the opening present value of the benefit obligation, taking into account material changes in the obligation during the year. The expected return on plan assets is based on an assessment made at the beginning of the year of long-term market returns on scheme assets, adjusted for the effect on the fair value of plan assets of contributions received and benefits paid during the year. The difference between the expected return on plan assets and the interest cost is recognized in the income statement as other finance income or expense.
Actuarial gains and losses are recognized in full in the group statement of recognized income and expense in the period in which they occur.
The defined benefit pension asset or liability in the balance sheet comprises the total for each plan of the present value of the defined benefit obligation (using a discount rate based on high quality corporate bonds), less the fair value of plan assets out of which the obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price.
Contributions to defined contribution schemes are recognized in the income statement in the period in which they become payable.
Corporate taxes
Income tax expense represents the sum of the tax currently payable and deferred tax.
The tax currently payable is based on the taxable profits for the period. Taxable profit differs from net profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other periods and it further excludes items that are never taxable or deductible. The group’s liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on all temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.
Deferred tax liabilities are recognized for all taxable temporary differences: |
| – | Except where the deferred tax liability arises on goodwill that is not tax deductible or the initial recognition of an asset or liability in a transaction thatis not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss. |
| – | In respect of taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where thetiming of the reversal of the temporary differences can be controlled by the group and it is probable that the temporary differences will not reverse inthe foreseeable future. |
| Deferred tax assets are recognized for all deductible temporary differences, carry-forward of unused tax assets and unused tax losses, to the extentthat it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax assets and unused tax losses can be utilized: |
| – | Except where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss. |
| – | In respect of deductible temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, deferred tax assets are only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized. |
The carrying amount of deferred income tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date.
Tax relating to items recognized directly in equity is recognized in equity and not in the income statement. |
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Customs duties and sales taxes
Revenues, expenses and assets are recognized net of the amount of customs duties or sales tax except: |
| – | Where the customs duty or sales tax incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case thecustoms duty or sales tax is recognized as part of the cost of acquisition of the asset or as part of the expense item as applicable. |
| – | Receivables and payables are stated with the amount of customs duty or sales tax included.
The net amount of sales tax recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the balance sheet. |
Own equity instruments
The group’s holding in its own equity instruments, including ordinary shares held by Employee Share Ownership Plans (ESOPs), are classified as ‘treasury shares’, and shown as deductions from shareholders’ equity at cost. Consideration received for the sale of such shares is also recognized in equity, with any difference between the proceeds from sale and the original cost being taken to revenue reserves. No gain or loss is recognized in the performance statements on the purchase, sale, issue or cancellation of equity shares.
Revenue
Revenue arising from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer and it can be reliably measured.
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1 Significant accounting policiescontinued
Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes.
Revenues associated with the sale of oil, natural gas, natural gas liquids, liquefied natural gas, petroleum and chemicals products and all other items are recognized when the title passes to the customer. Physical exchanges are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical exchange. Similarly, where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no purchase or sale is recorded. Additionally, where forward sale and purchase contracts for oil, natural gas or power have been determined to be for trading purposes, the associated sales and purchases are reported net within sales and other operating revenues whether or not physical delivery has occurred.
Generally, revenues from the production of oil and natural gas properties in which the group has an interest with joint venture partners are recognized on the basis of the group’s working interest in those properties (the entitlement method). Differences between the production sold and the group’s share of production are not significant.
Interest income is recognized as the interest accrues (using the effective interest rate method that is the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument) to the net carrying amount of the financial asset.
Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.
Research
Research costs are expensed as incurred.
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use.
All other finance costs are recognized in the income statement in the period in which they are incurred.
Use of estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting period. Actual outcomes could differ from those estimates.
Impact of new International Financial Reporting Standards
Adopted for 2006
The following amendments to IFRS and IFRIC interpretations have been adopted by the group with effect from 1 January 2006.
Amendment to IAS 21 ‘The Effects of Changes in Foreign Exchange Rates’– ‘Net Investment in a Foreign Operation’ was issued in December 2005. The amendment clarifies the requirements of IAS 21 regarding an entity’s investment in foreign operations. This amendment was adopted by the EU in May 2006. There was no material impact on the group’s reported income or net assets as a result of adoption of this amendment.
The IASB issued an amendment to the fair value option in IAS 39 in June 2005. The option to irrevocably designate, on initial recognition, any financial instruments as ones to be measured at fair value with gains and losses recognized in profit and loss has now been restricted to those financial instruments meeting certain criteria. The criteria are where such designation eliminates or significantly reduces an accounting mismatch, when a group of financial assets, financial liabilities or both are managed and their performance is evaluated on a fair value basis in accordance with a documented risk management or investment strategy, and when an instrument contains an embedded derivative that meets particular conditions. The group has not designated any financial instruments as being at-fair-value-through-profit-and-loss, thus there was no effect on the group’s reported income or net assets as a result of adoption of this amendment.
In August 2005, the IASB issued amendments to IAS 39 and IFRS 4 ‘Insurance Contracts’ regarding financial guarantee contracts. These amendments require the issuer of financial guarantee contracts to account for them under IAS 39 as opposed to IFRS 4 unless an issuer has previously asserted explicitly that it regards such contracts as insurance contracts and has used accounting applicable to insurance contracts. In these instances the issuer may elect to apply either IAS 39 or IFRS 4. Under the amended IAS 39, a financial guarantee contract is initially recognized at fair value and is subsequently measured at the higher of (a) the amount determined in accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’ and (b) the amount initially recognized, less, when appropriate, cumulative amortization recognized in accordance with IAS 18 ‘Revenue’. This standard impacts guarantees given by group companies in respect of equity-accounted entities as well as in respect of other third parties; these are recorded in the group’s financial statements at initial fair value less cumulative amortization. The effect on the group’s reported income and net assets as a result of adoption of this amendment was not material.
In addition, in 2006 BP has adopted IFRIC 5 ‘Rights to Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds’ and IFRIC 6 ‘Liabilities Arising from Participating in a Specific Market – Waste Electrical and Electronic Equipment’ and has decided to early adopt IFRIC 7 ‘Applying IAS 29 for the First Time’, IFRIC 8 ‘Scope of IFRS 2 – Share-based payment’ and IFRIC 9 ‘Reassessment of embedded derivatives’. There were no changes in accounting policy and no restatement of financial information consequent upon adoption of these interpretations.
Not yet adopted
The following pronouncements from the IASB will become effective for future financial reporting periods and have not yet been adopted by the group.
In August 2005, the IASB issued IFRS 7 ‘Financial Instruments – Disclosures’ which is effective for annual periods beginning on or after 1 January 2007. Upon adoption, the group will disclose additional information about its financial instruments, their significance and the nature and extent of risks to which they give rise. More specifically, the group will be required to make specified minimum disclosures about credit risk, liquidity risk and market risk. There will be no effect on reported income or net assets.
Also in August 2005, ‘IAS 1 Amendment – Presentation of Financial Statements: Capital Disclosures’ was issued by the IASB, which requires disclosures of an entity’s objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and the consequences of any non-compliance. This is effective for annual periods beginning on or after 1 January 2007. There will be no effect on the group’s reported income or net assets.
Back to Contents
1 Significant accounting policiescontinued
IFRS 8 ‘Operating Segments’ was issued in October 2006 and defines operating segments as components of an entity about which separate financial information is available and is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. The new standard sets out the required disclosures for operating segments and is effective for annual periods beginning on or after 1 January 2009. BP has not yet completed its evaluation of the impact on its disclosures of adopting IFRS 8. There will be no effect on the group’s reported income or net assets. IFRS 8 has not yet been adopted by the EU.
Three further IFRIC interpretations, issued in late 2006, are not yet effective and have not yet been adopted by the EU.
IFRIC 10 ‘Interim Financial Reporting and Impairment’ prohibits the reversal of an impairment loss relating to goodwill or certain financial assets made in an earlier interim period in the same annual period.
IFRIC 11 ‘IFRS 2 – Group and Treasury Share Transactions’ deals with share-based payment arrangements within a group and share-based payment arrangements satisfied by using treasury shares.
The directors do not anticipate that the adoption of these interpretations will have a material effect on the reported income or net assets of the group.
IFRIC 12 ‘Service Concession Arrangements’ gives guidance on the accounting by operators for public-to-private service concession arrangements.
BP has not yet completed its evaluation of the impact of adopting this interpretation.
Back to Contents
2 Resegmentation
| With effect from 1 January 2006 the following changes to the business segment boundaries have been implemented: |
| (a) | Following the sale of Innovene to INEOS in December 2005, the transfer of three equity-accounted entities (Shanghai SECCO Petrochemical Company Limited in China and Polyethylene Malaysia Sdn Bhd and Ethylene Malaysia Sdn Bhd, both in Malaysia), previously reported in Other businesses and corporate, to Refining and Marketing. |
| (b) | The formation of BP Alternative Energy in November 2005 has resulted in the transfer of certain mid-stream assets and activities to Gas, Power and Renewables: |
| – | South Houston Green Power co-generation facility (in the Texas City refinery) from Refining and Marketing. |
| – | Watson Cogeneration (in the Carson refinery) from Refining and Marketing. |
| – | Phu My Phase 3 CCGT plant in Vietnam from Exploration and Production. |
| (c) | The transfer of Hydrogen for Transport activities from Gas, Power and Renewables to Refining and Marketing.
The impact of the changes described above is shown in the tables below. |
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| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | Gas, | | Other | | Consolidation | | | | | | Consolidation | | | |
| | Exploration | | Refining | | Power | | businesses | | adjustment | | | | | | adjustment | | Total | |
| | and | | and | | and | | and | | and | | Total | | Innovene | | and | | continuing | |
| By business – as reported | Production | | Marketing | | Renewables | | corporate | | eliminations | | group | | operations | | eliminations | | operations | |
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| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| Segment sales and other operating revenues | 47,210 | | 213,465 | | 25,557 | | 21,295 | | (55,359 | ) | 252,168 | | (20,627 | ) | 8,251 | | 239,792 | |
| Less: sales between businesses | (32,606 | ) | (11,407 | ) | (3,095 | ) | (8,251 | ) | 55,359 | | – | | 8,251 | | (8,251 | ) | – | |
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| Third party sales | 14,604 | | 202,058 | | 22,462 | | 13,044 | | – | | 252,168 | | (12,376 | ) | – | | 239,792 | |
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| Segment results | | | | | | | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 25,508 | | 6,442 | | 1,104 | | (523 | ) | (208 | ) | 32,323 | | (668 | ) | 527 | | 32,182 | |
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| Assets and liabilities | | | | | | | | | | | | | | | | | | |
| Net assets (liabilities) | 73,092 | | 45,125 | | 5,095 | | (2,602 | ) | (40,260 | ) | 80,450 | | | | | | | |
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| By business – as restated | | | | | | | | | | | | | | | | | | |
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| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| Segment sales and other operating revenues | 47,210 | | 213,326 | | 25,696 | | 21,295 | | (55,359 | ) | 252,168 | | (20,627 | ) | 8,251 | | 239,792 | |
| Less: sales between businesses | (32,606 | ) | (11,407 | ) | (3,095 | ) | (8,251 | ) | 55,359 | | – | | 8,251 | | (8,251 | ) | – | |
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| Third party sales | 14,604 | | 201,919 | | 22,601 | | 13,044 | | – | | 252,168 | | (12,376 | ) | – | | 239,792 | |
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| Segment results | | | | | | | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 25,502 | | 6,426 | | 1,172 | | (569 | ) | (208 | ) | 32,323 | | (668 | ) | 527 | | 32,182 | |
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| Assets and liabilities | | | | | | | | | | | | | | | | | | |
| Net assets (liabilities) | 73,060 | | 45,234 | | 5,587 | | (3,171 | ) | (40,260 | ) | 80,450 | | | | | | | |
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| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2004 | |
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| | | | | | Gas, | | Other | | Consolidation | | | | | | Consolidation | | | |
| | Exploration | | Refining | | Power | | businesses | | adjustment | | | | | | adjustment | | Total | |
| | and | | and | | and | | and | | and | | Total | | Innovene | | and | | continuing | |
| By business – as reported | Production | | Marketing | | Renewables | | corporate | | eliminations | | group | | operations | | eliminations | | operations | |
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| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| Segment sales and other operating revenues | 34,700 | | 170,749 | | 23,859 | | 17,994 | | (43,999 | ) | 203,303 | | (17,448 | ) | 6,169 | | 192,024 | |
| Less: sales between businesses | (24,756 | ) | (10,632 | ) | (2,442 | ) | (6,169 | ) | 43,999 | | – | | 6,169 | | (6,169 | ) | – | |
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| Third party sales | 9,944 | | 160,117 | | 21,417 | | 11,825 | | – | | 203,303 | | (11,279 | ) | – | | 192,024 | |
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| Segment results | | | | | | | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 18,087 | | 6,544 | | 954 | | (362 | ) | (191 | ) | 25,032 | | 526 | | 188 | | 25,746 | |
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| By business – as restated | | | | | | | | | | | | | | | | | | |
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| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| Segment sales and other operating revenues | 34,700 | | 170,639 | | 23,969 | | 17,994 | | (43,999 | ) | 203,303 | | (17,448 | ) | 6,169 | | 192,024 | |
| Less: sales between businesses | (24,756 | ) | (10,632 | ) | (2,442 | ) | (6,169 | ) | 43,999 | | – | | 6,169 | | (6,169 | ) | – | |
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| Third party sales | 9,944 | | 160,007 | | 21,527 | | 11,825 | | – | | 203,303 | | (11,279 | ) | – | | 192,024 | |
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| Segment results | | | | | | | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 18,085 | | 6,506 | | 1,003 | | (371 | ) | (191 | ) | 25,032 | | 526 | | 188 | | 25,746 | |
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Back to Contents
3 Oil and natural gas reserves estimates
At the end of 2006, BP adopted the US Securities and Exchange Commission (SEC) rules for estimating oil and natural gas reserves for all accounting and reporting purposes instead of the UK accounting rules contained in the Statement of Recommended Practice ‘Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities’ (UK SORP). The main differences relate to the SEC requirement to use year-end prices, the application of SEC interpretations of SEC regulations relating to the use of technology (mainly seismic) to estimate reserves in the reservoir away from wellbores and the reporting of fuel gas (i.e. gas used for fuel in operations) within proved reserves. Consequently, reserves quantities under SEC rules differ from those that would be reported under application of the UK SORP.
The change to SEC reserves represents a simplification of the group’s reserves reporting, as in the future only one set of reserves estimates will be disclosed. In addition, the use of SEC reserves for accounting purposes will bring our IFRS and US GAAP reporting into closer alignment, as well as making our results more comparable with those of our major competitors.
This change in accounting estimate has a direct impact on the amount of depreciation, depletion and amortization (DD&A) charged in the income statement in respect of oil and natural gas properties which are depreciated on a unit-of-production basis as described in Note 1. The change in estimate is applied prospectively, with no restatement of prior periods’ results. The group’s actual DD&A charge for the year is $9,128 million, whereas the charge based on UK SORP reserves would have been $9,057 million, i.e. an increase of $71 million due to the change in reserves estimates which was used to calculate DD&A for the last three months of the year. Over the life of a field this change would have no overall effect on DD&A but the estimated effect for 2007 is expected to be an increase of approximately $400 million to $500 million for the group.
4 Acquisitions
Acquisitions in 2006
BP made a number of minor acquisitions in 2006 for a total consideration of $256 million. All these business combinations were in the Gas, Power and Renewables segment and were accounted for using the acquisition method of accounting. Fair value adjustments were made to the acquired assets and liabilities and goodwill of $64 million arose on these acquisitions.
Acquisitions in 2005
BP made a number of minor acquisitions in 2005 for a total consideration of $84 million. All these business combinations were accounted for using the acquisition method of accounting. No significant fair value adjustments were made to the acquired assets and liabilities. Goodwill of $27 million arose on these acquisitions. There was also additional goodwill on the Solvay acquisition of $59 million (see below).
Acquisitions in 2004
On 2 November 2004, Solvay exercised its option to sell its interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America to BP. Solvay held 50% of BP Solvay Polyethylene Europe and 51% of BP Solvay Polyethylene North America. On completion, the two entities, which manufacture and market high-density polyethylene, became wholly owned subsidiaries of BP. The total consideration for the acquisition was $1,391 million, subject to final closing adjustments. There were closing adjustments and selling costs in 2005 amounting to $59 million. These created additional goodwill of $59 million, which was written off. Other minor acquisitions were made for a total consideration of $14 million. All business combinations have been accounted for using the acquisition method of accounting. The fair value of the property, plant and equipment was estimated by determining the net present value of future cash flows. No significant adjustments were made to the other assets and liabilities acquired. The assets and liabilities acquired as part of the 2004 acquisitions are shown in aggregate in the table below.
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| | on | | Fair value | | | |
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| Property, plant and equipment | 703 | | 760 | | 1,463 | |
| Intangible assets | 15 | | – | | 15 | |
| Current assets (excluding cash) | 721 | | – | | 721 | |
| Cash and cash equivalents | 36 | | – | | 36 | |
| Trade and other payables | (329 | ) | – | | (329 | ) |
| Deferred tax liabilities | – | | (185 | ) | (185 | ) |
| Defined benefit pension plan deficits | (3 | ) | – | | (3 | ) |
| Net investment in equity-accounted entities transferred to full consolidation | (547 | ) | (94 | ) | (641 | ) |
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| Net assets acquired | 596 | | 481 | | 1,077 | |
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| Goodwill | | | | | 328 | |
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| Consideration | | | | | 1,405 | |
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Back to Contents
5 Non-current assets held for sale and discontinued operations
Non-current assets held for sale
On 27 June 2006, BP announced its intention to sell the Coryton refinery in the UK, following a review of its European refinery portfolio which concluded that the group would optimise its value by focusing on a smaller, but more advantaged refining portfolio in Europe. In addition, given the integrated nature of the operations, the bitumen business in the UK is also included with the divestment, along with the Coryton bulk terminal (together ‘the Coryton disposal group’).
At 31 December 2006, negotiations for the sale were in progress and the assets and associated liabilities were classified as a disposal group held for sale. No impairment loss was recognized at the time of reclassification of the Coryton disposal group as held for sale nor at 31 December 2006.
The major classes of assets and liabilities of the Coryton disposal group, reported within the Refining and Marketing segment, classified as held for sale at 31 December 2006 are set out below.
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| Assets | | |
| Property, plant and equipment | 564 | |
| Goodwill | 60 | |
| Inventories | 454 | |
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| Assets classified as held for sale | 1,078 | |
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| Current liabilities | 54 | |
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| Liabilities directly associated with assets classified as held for sale | 54 | |
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In addition, accumulated foreign exchange gains recognized directly in equity relating to the Coryton disposal group amounted to $122 million at 31 December 2006. On disposal such foreign exchange differences are recycled to the income statement.
On 1 February 2007, it was agreed to sell the Coryton disposal group, subject to required regulatory approval, to Petroplus Holdings AG, an independent refiner and wholesaler of petroleum products headquartered in Zug, Switzerland, for a sale price of $1.4 billion, plus hydrocarbons to be valued at closing.
Discontinued operations
The sale of Innovene, BP’s olefins, derivatives and refining group, to INEOS was completed on 16 December 2005.
The Innovene operations represented a separate major line of business for BP. As a result of the sale, these operations were treated as discontinued operations for the year ended 31 December 2005. A single amount was shown on the face of the income statement comprising the post-tax result of discontinued operations and the post-tax loss recognized on the remeasurement to fair value less costs to sell and on disposal of the discontinued operation. That is, the income and expenses of Innovene are reported separately from the continuing operations of the BP group. The table below provides further detail of the amount shown in the income statement.
In the cash flow statement, the cash provided by the operating activities of Innovene has been separated from that of the rest of the group and reported as a single line item.
Gross proceeds received amounted to $8,477 million. In 2005 there were selling costs of $120 million and initial closing adjustments of $43 million. In 2006 there was a final closing adjustment of $34 million. The remeasurement to fair value less costs to sell resulted in a loss of $775 million before tax ($184 million recognized in 2006 and $591 million in 2005).
Financial information for the Innovene operations after group eliminations is presented below.
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| Total revenues and other income | – | | 12,441 | | 11,327 | |
| Expenses | – | | 11,709 | | 12,041 | |
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| Profit (loss) before interest and taxation | – | | 732 | | (714 | ) |
| Other finance income (expense) | – | | 3 | | (17 | ) |
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| Profit (loss) before taxation and loss recognized on remeasurement to fair value less costs to sell and on disposal | – | | 735 | | (731 | ) |
| Loss recognized on the remeasurement to fair value less costs to sell and on disposal | (184 | ) | (591 | ) | – | |
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| Profit (loss) before taxation from Innovene operations | (184 | ) | 144 | | (731 | ) |
| Tax (charge) credit | | | | | | |
| on profit (loss) before loss recognized on remeasurement to fair value less costs to sell and on disposal | 166 | | (306 | ) | 109 | |
| on loss recognized on the remeasurement to fair value less costs to sell and on disposal | (7 | ) | 346 | | – | |
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| Profit (loss) from Innovene operations | (25 | ) | 184 | | (622 | ) |
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| Earnings (loss) per share from Innovene operations – cents | | | | | | |
| Basic | (0.13 | ) | 0.87 | | (2.85 | ) |
| Diluted | (0.12 | ) | 0.86 | | (2.79 | ) |
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| The cash flows of Innovene operations are presented below | | | | | | |
| Net cash provided by (used in) operating activities | – | | 970 | | (669 | ) |
| Net cash used in investing activities | – | | (524 | ) | (1,731 | ) |
| Net cash provided by (used in) financing activities | – | | (446 | ) | 2,400 | |
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Further information is contained in Note 6.
Back to Contents
6 Disposals
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| Proceeds from the sale of Innovene operations | (34 | ) | 8,304 | | – | |
| Proceeds from the sale of other businesses | 325 | | 93 | | 725 | |
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| Proceeds from the sale of businesses | 291 | | 8,397 | | 725 | |
| Proceeds from disposal of fixed assets | 5,963 | | 2,803 | | 4,236 | |
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| | 6,254 | | 11,200 | | 4,961 | |
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| By business | | | | | | |
| Exploration and Production | 4,005 | | 1,416 | | 914 | |
| Refining and Marketing | 1,789 | | 888 | | 1,007 | |
| Gas, Power and Renewables | 297 | | 540 | | 144 | |
| Other businesses and corporate | 163 | | 8,356 | | 2,896 | |
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| | 6,254 | | 11,200 | | 4,961 | |
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As part of the strategy to upgrade the quality of its asset portfolio, the group has an active programme to dispose of non-strategic assets. In the normal course of business in any particular year, the group may sell interests in exploration and production properties, service stations and pipeline interests as well as non-core businesses.
Cash received during the year from disposals amounted to $6.3 billion (2005 $11.2 billion and 2004 $5.0 billion). The major transactions in 2006 were the disposals of our interests in the Gulf of Mexico Shelf and our interest in the Shenzi discovery in the Gulf of Mexico. The divestment of Innovene contributed $8.3 billion to the total in 2005. The major transactions in 2004 that generated over $2.3 billion of proceeds were the sale of the group’s investments in PetroChina and Sinopec. The principal transactions generating the proceeds for each business segment are described below.
Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. During 2006 the major transactions were disposals of our interests in the Gulf of Mexico Shelf, in the Shenzi discovery in the Gulf of Mexico, in the Statfjord oil and gas field and in the Luva gas field in the North Sea. We also divested our interests in a number of onshore fields in South Louisiana, interests in fields in the North Sea, the Gulf of Suez and Venezuela, and part of an interest in Colombia. During 2005, the major transaction was the sale of the group’s interest in the Ormen Lange field in Norway. In addition, the group sold interests in oil and natural gas properties in Venezuela, Canada and the Gulf of Mexico. In 2004, in the US, we sold 45% of our interest in King’s Peak in the deepwater Gulf of Mexico to Marubeni Oil & Gas, divested our interest in Swordfish, and additionally sold various properties, including our interest in the South Pass 60 property in the Gulf of Mexico Shelf. In Canada, BP sold various assets in Alberta to Fairborne Energy. In Indonesia, we disposed of our interest in the Kangean Production Sharing Contract and our participating interest in the Muriah Production Sharing Contract.
Refining and Marketing
The churn of retail assets represents a significant element of the total in all three years. In addition, in 2006, we disposed of our interests in Zhenhai Refining and Chemicals Company in China and in Eiffage, the French-based construction company. We also exited the retail market in the Czech Republic and disposed of our interests in a number of pipelines. During 2005, the group sold a number of regional retail networks in the US and in addition its retail network in Malaysia. During 2004, major transactions included the sale of the Singapore refinery, the divestment of the European speciality intermediate chemicals business and the Cushing and other pipeline interests in the US.
Gas, Power and Renewables
During 2006, we disposed of our shareholding in Enagas, the Spanish gas transport grid operator. In 2005, the group sold its interest in the Interconnector pipeline and a power plant at Great Yarmouth in the UK. During 2004, the group sold its interest in two Canadian natural gas liquids plants.
Other businesses and corporate
During 2006, the group disposed of miscellaneous non-core businesses and assets. 2005 includes the proceeds from the sale of Innovene. The disposal of the group’s investments in PetroChina and Sinopec were the major transactions in 2004. In addition, the group sold its US speciality intermediate chemicals and fabrics and fibres businesses.
Summarized financial information for the sale of businesses is shown below.
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| The disposals comprise the following | | | | | | |
| Non-current assets | 143 | | 6,452 | | 1,046 | |
| Other current assets | 169 | | 4,779 | | 477 | |
| Non-current liabilities | (10 | ) | (364 | ) | (44 | ) |
| Current liabilities | (70 | ) | (2,488 | ) | (59 | ) |
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| | 232 | | 8,379 | | 1,420 | |
| Profit (loss) on sale of businesses | 167 | | 18 | | (695 | ) |
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| Total consideration | 399 | | 8,397 | | 725 | |
| Consideration not yet received | (74 | ) | – | | – | |
| Closing adjustments associated with the sale of Innovene | (34 | ) | – | | – | |
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| Proceeds from the sale of businessesa | 291 | | 8,397 | | 725 | |
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| a | Includes cash and cash equivalents disposed of $2 million (2005 $15 million and 2004 $10 million). |
Back to Contents
7 Segmental analysis
The group’s primary format for segment reporting is business segments and the secondary format is geographical segments. The risks and returns of the group’s operations are primarily determined by the nature of the different activities that the group engages in, rather than the geographical location of these operations. This is reflected by the group’s organizational structure and the group’s internal financial reporting systems.
BP has three reportable operating segments: Exploration and Production; Refining and Marketing; and Gas, Power and Renewables. Exploration and Production’s activities include oil and natural gas exploration and field development and production, together with pipeline transportation and natural gas processing. The activities of Refining and Marketing include oil supply and trading as well as refining and petrochemicals manufacturing and marketing. Gas, Power and Renewables activities include marketing and trading of gas and power, marketing of liquefied natural gas, natural gas liquids and low-carbon power generation through the Alternative Energy business. The group is managed on an integrated basis.
Other businesses and corporate comprises Finance, the group’s aluminum asset, interest income and costs relating to corporate activities worldwide.
The accounting policies of operating segments are the same as those described in Note 1.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenue and segment result include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation.
The group’s geographical segments are based on the location of the group’s assets. The UK and the US are significant countries of activity for the group; the other geographical segments are determined by geographical location.
Sales to external customers are based on the location of the seller, which in most circumstances is not materially different from the location of the customer. Crude oil and LNG are commodities for which there is an international market and buyers and sellers can be widely separated geographically. The UK segment includes the UK-based international activities of Refining and Marketing.
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| | | | | | | | | | | | | | | | | | 2006 | |
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| | | | | | Gas, | | Other | | Consolidation | | | | | | Consolidation | | | |
| | Exploration | | Refining | | Power | | businessess | | adjustment | | | | | | adjustment | | Total | |
| | and | | and | | and | | and | | and | | Total | | Innovene | | and | | continuing | |
| By business | Production | | Marketing | | Renewables | | corporate | | eliminations | | group | | operations | | eliminations | a | operations | |
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| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| Segment sales and other operating revenues | 52,600 | | 232,855 | | 23,708 | | 1,009 | | (44,266 | ) | 265,906 | | – | | – | | 265,906 | |
| Less: sales between businesses | (36,171 | ) | (4,076 | ) | (4,019 | ) | – | | 44,266 | | – | | – | | – | | – | |
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| Third party sales | 16,429 | | 228,779 | | 19,689 | | 1,009 | | – | | 265,906 | | – | | – | | 265,906 | |
| Equity-accounted earnings | 3,517 | | 341 | | 138 | | (1 | ) | – | | 3,995 | | – | | – | | 3,995 | |
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| Segment revenues | 19,946 | | 229,120 | | 19,827 | | 1,008 | | – | | 269,901 | | – | | – | | 269,901 | |
| Interest and other revenues | – | | – | | – | | – | | 701 | | 701 | | – | | – | | 701 | |
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| Total revenues | 19,946 | | 229,120 | | 19,827 | | 1,008 | | 701 | | 270,602 | | – | | – | | 270,602 | |
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| Segment results | | | | | | | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 29,629 | | 5,541 | | 1,321 | | (1,069 | ) | 52 | | 35,474 | | 184 | | – | | 35,658 | |
| Finance costs and other finance expense | – | | – | | – | | – | | (516 | ) | (516 | ) | – | | – | | (516 | ) |
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| Profit (loss) before taxation | 29,629 | | 5,541 | | 1,321 | | (1,069 | ) | (464 | ) | 34,958 | | 184 | | – | | 35,142 | |
| Taxation | – | | – | | – | | – | | (12,357 | ) | (12,357 | ) | (159 | ) | – | | (12,516 | ) |
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| Profit (loss) for the year | 29,629 | | 5,541 | | 1,321 | | (1,069 | ) | (12,821 | ) | 22,601 | | 25 | | – | | 22,626 | |
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| Assets and liabilities | | | | | | | | | | | | | | | | | | |
| Segment assets | 99,310 | | 80,964 | | 27,398 | | 14,184 | | (4,799 | ) | 217,057 | | | | | | | |
| Tax receivable | – | | – | | – | | – | | 544 | | 544 | | | | | | | |
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| Total assets | 99,310 | | 80,964 | | 27,398 | | 14,184 | | (4,255 | ) | 217,601 | | | | | | | |
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| Includes | | | | | | | | | | | | | | | | | | |
| Equity-accounted investments | 15,510 | | 4,675 | | 853 | | 11 | | – | | 21,049 | | | | | | | |
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| Segment liabilities | (21,787 | ) | (33,399 | ) | (21,708 | ) | (14,555 | ) | 4,074 | | (87,375 | ) | | | | | | |
| Current tax payable | – | | – | | – | | – | | (2,635 | ) | (2,635 | ) | | | | | | |
| Finance debt | – | | – | | – | | – | | (24,010 | ) | (24,010 | ) | | | | | | |
| Deferred tax liabilities | – | | – | | – | | – | | (18,116 | ) | (18,116 | ) | | | | | | |
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| Total liabilities | (21,787 | ) | (33,399 | ) | (21,708 | ) | (14,555 | ) | (40,687 | ) | (132,136 | ) | | | | | | |
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| Other segment information | | | | | | | | | | | | | | | | | | |
| Capital expenditure and acquisitions | | | | | | | | | | | | | | | | | | |
| Intangible assets | 1,614 | | 253 | | 192 | | 43 | | – | | 2,102 | | | | | | | |
| Property, plant and equipment | 10,227 | | 2,733 | | 337 | | 232 | | – | | 13,529 | | | | | | | |
| Other | 1,277 | | 158 | | 159 | | 6 | | – | | 1,600 | | | | | | | |
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| Total | 13,118 | | 3,144 | | 688 | | 281 | | – | | 17,231 | | | | | | | |
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| Depreciation, depletion and amortization | 6,533 | | 2,244 | | 192 | | 159 | | – | | 9,128 | | – | | – | | 9,128 | |
| Impairment losses | 137 | | 155 | | 100 | | 69 | | – | | 461 | | – | | – | | 461 | |
| Impairment reversals | 340 | | – | | – | | – | | – | | 340 | | – | | – | | 340 | |
| Loss on remeasurement to fair value less costs to sell | | | | | | | | | | | | | | | | | | |
| and on disposal of Innovene operations | – | | – | | – | | 184 | | – | | 184 | | (184 | ) | – | | – | |
| Losses on sale of businesses and fixed assets | 195 | | 228 | | – | | 5 | | – | | 428 | | – | | – | | 428 | |
| Gains on sale of businesses and fixed assets | 2,309 | | 1,112 | | 193 | | 100 | | – | | 3,714 | | – | | – | | 3,714 | |
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Back to Contents
7 Segmental analysis continued
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2005 | |
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| | | | | | Gas, | | Other | | Consolidation | | | | | | Consolidation | | | |
| | Exploration | | Refining | | Power | | businesses | | adjustment | | | | | | adjustment | | Total | |
| | and | | and | | and | | and | | and | | Total | | Innovene | | and | | continuing | |
| By business | Production | | Marketing | | Renewables | | corporate | | eliminations | | group | | operations | | eliminations | a | operations | |
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| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| Segment sales and other operating revenues | 47,210 | | 213,326 | | 25,696 | | 21,295 | | (55,359 | ) | 252,168 | | (20,627 | ) | 8,251 | | 239,792 | |
| Less: sales between businesses | (32,606 | ) | (11,407 | ) | (3,095 | ) | (8,251 | ) | 55,359 | | – | | 8,251 | | (8,251 | ) | – | |
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| Third party sales | 14,604 | | 201,919 | | 22,601 | | 13,044 | | – | | 252,168 | | (12,376 | ) | – | | 239,792 | |
| Equity-accounted earnings | 3,232 | | 249 | | 62 | | (14 | ) | – | | 3,529 | | 14 | | – | | 3,543 | |
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| Segment revenues | 17,836 | | 202,168 | | 22,663 | | 13,030 | | – | | 255,697 | | (12,362 | ) | – | | 243,335 | |
| Interest and other revenues | – | | – | | – | | – | | 689 | | 689 | | (76 | ) | – | | 613 | |
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| Total revenues | 17,836 | | 202,168 | | 22,663 | | 13,030 | | 689 | | 256,386 | | (12,438 | ) | – | | 243,948 | |
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| Segment results | | | | | | | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 25,502 | | 6,426 | | 1,172 | | (569 | ) | (208 | ) | 32,323 | | (668 | ) | 527 | | 32,182 | |
| Finance costs and other finance expense | – | | – | | – | | – | | (758 | ) | (758 | ) | (3 | ) | – | | (761 | ) |
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| Profit (loss) before taxation | 25,502 | | 6,426 | | 1,172 | | (569 | ) | (966 | ) | 31,565 | | (671 | ) | 527 | | 31,421 | |
| Taxation | – | | – | | – | | – | | (9,248 | ) | (9,248 | ) | 133 | | (173 | ) | (9,288 | ) |
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| Profit (loss) for the year | 25,502 | | 6,426 | | 1,172 | | (569 | ) | (10,214 | ) | 22,317 | | (538 | ) | 354 | | 22,133 | |
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| Assets and liabilities | | | | | | | | | | | | | | | | | | |
| Segment assets | 93,447 | | 77,485 | | 28,952 | | 12,144 | | (5,326 | ) | 206,702 | | | | | | | |
| Tax receivable | – | | – | | – | | – | | 212 | | 212 | | | | | | | |
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| Total assets | 93,447 | | 77,485 | | 28,952 | | 12,144 | | (5,114 | ) | 206,914 | | | | | | | |
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| Includes | | | | | | | | | | | | | | | | | | |
| Equity-accounted investments | 14,657 | | 4,336 | | 771 | | 9 | | – | | 19,773 | | | | | | | |
| Segment liabilities | (20,387 | ) | (32,251 | ) | (23,365 | ) | (15,315 | ) | 4,548 | | (86,770 | ) | | | | | | |
| Current tax payable | – | | – | | – | | – | | (4,274 | ) | (4,274 | ) | | | | | | |
| Finance debt | – | | – | | – | | – | | (19,162 | ) | (19,162 | ) | | | | | | |
| Deferred tax liabilities | – | | – | | – | | – | | (16,258 | ) | (16,258 | ) | | | | | | |
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| Total liabilities | (20,387 | ) | (32,251 | ) | (23,365 | ) | (15,315 | ) | (35,146 | ) | (126,464 | ) | | | | | | |
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| Other segment information | | | | | | | | | | | | | | | | | | |
| Capital expenditure and acquisitions | | | | | | | | | | | | | | | | | | |
| Intangible assets | 989 | | 451 | | 31 | | 10 | | – | | 1,481 | | | | | | | |
| Property, plant and equipment | 8,751 | | 2,036 | | 199 | | 779 | | – | | 11,765 | | | | | | | |
| Other | 497 | | 373 | | 5 | | 28 | | – | | 903 | | | | | | | |
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| Total | 10,237 | | 2,860 | | 235 | | 817 | | – | | 14,149 | | | | | | | |
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| Depreciation, depletion and amortization | 6,033 | | 2,382 | | 235 | | 533 | | – | | 9,183 | | (412 | ) | – | | 8,771 | |
| Impairment losses | 266 | | 93 | | – | | 59 | | – | | 418 | | (59 | ) | – | | 359 | |
| Loss on remeasurement to fair value less | | | | | | | | | | | | | | | | | | |
| costs to sell and on disposal of Innovene | | | | | | | | | | | | | | | | | | |
| operations | – | | – | | – | | 591 | | – | | 591 | | (591 | ) | – | | – | |
| Losses on sale of businesses and fixed assets | 39 | | 64 | | – | | 6 | | – | | 109 | | – | | – | | 109 | |
| Gains on sale of businesses and fixed assets | 1,198 | | 241 | | 55 | | 47 | | – | | 1,541 | | (3 | ) | – | | 1,538 | |
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Back to Contents
7 Segmental analysis continued
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2004 | |
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| | | | | | Gas, | | Other | | Consolidation | | | | | | Consolidation | | | |
| | Exploration | | Refining | | Power | | businesses | | adjustment | | | | | | adjustment | | Total | |
| | and | | and | | and | | and | | and | | Total | | Innovene | | and | | continuing | |
| By business | Production | | Marketing | | Renewables | | corporate | | eliminations | | group | | operations | | eliminations | a | operations | |
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| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| Segment sales and other operating revenues | 34,700 | | 170,639 | | 23,969 | | 17,994 | | (43,999 | ) | 203,303 | | (17,448 | ) | 6,169 | | 192,024 | |
| Less: sales between businesses | (24,756 | ) | (10,632 | ) | (2,442 | ) | (6,169 | ) | 43,999 | | – | | 6,169 | | (6,169 | ) | – | |
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| Third party sales | 9,944 | | 160,007 | | 21,527 | | 11,825 | | – | | 203,303 | | (11,279 | ) | – | | 192,024 | |
| Equity-accounted earnings | 1,983 | | 262 | | 35 | | (12 | ) | – | | 2,268 | | 12 | | – | | 2,280 | |
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| Segment revenues | 11,927 | | 160,269 | | 21,562 | | 11,813 | | – | | 205,571 | | (11,267 | ) | – | | 194,304 | |
| Interest and other revenues | – | | – | | – | | – | | 673 | | 673 | | (58 | ) | – | | 615 | |
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| Total revenues | 11,927 | | 160,269 | | 21,562 | | 11,813 | | 673 | | 206,244 | | (11,325 | ) | – | | 194,919 | |
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| Segment results | | | | | | | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 18,085 | | 6,506 | | 1,003 | | (371 | ) | (191 | ) | 25,032 | | 526 | | 188 | | 25,746 | |
| Finance costs and other finance expense | – | | – | | – | | – | | (797 | ) | (797 | ) | 17 | | – | | (780 | ) |
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| Profit (loss) before taxation | 18,085 | | 6,506 | | 1,003 | | (371 | ) | (988 | ) | 24,235 | | 543 | | 188 | | 24,966 | |
| Taxation | – | | – | | – | | – | | (6,973 | ) | (6,973 | ) | (53 | ) | (56 | ) | (7,082 | ) |
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| Profit (loss) for the year | 18,085 | | 6,506 | | 1,003 | | (371 | ) | (7,961 | ) | 17,262 | | 490 | | 132 | | 17,884 | |
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| Other segment information | | | | | | | | | | | | | | | | | | |
| Depreciation, depletion and amortization | 5,583 | | 2,532 | | 218 | | 679 | | – | | 9,012 | | (483 | ) | – | | 8,529 | |
| Impairment losses | 435 | | 195 | | – | | 891 | | – | | 1,521 | | (879 | ) | – | | 642 | |
| Impairment reversals | 31 | | – | | – | | – | | – | | 31 | | – | | – | | 31 | |
| Losses on sale of businesses and fixed assets | 227 | | 371 | | – | | 416 | | – | | 1,014 | | (235 | ) | – | | 779 | |
| Gains on sale of businesses and fixed assets | 162 | | 104 | | 56 | | 1,365 | | – | | 1,687 | | (2 | ) | – | | 1,685 | |
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| a | In the circumstances of discontinued operations, IFRS requires that the profits earned by the discontinued operations, in this case the Innovene operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa. This adjustment has two offsetting elements: the net margin on crude refined by Innovene as substantially all crude for its refineries was supplied by BP and most of the refined products manufactured were taken by BP; and the margin on sales of feedstock from BP’s US refineries to Innovene’s manufacturing plants. The profits attributable to individual segments are not affected by this adjustment. This representation does not indicate the profits earned by continuing or Innovene operations, as if they were standalone entities, for past periods or likely to be earned in future periods. |
Back to Contents
7 Segmental analysis continued
| | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | 2006 | |
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| | | | | | | | | | Consolidation | | | |
| | | | | | | | | | adjustment | | | |
| | | | Rest of | | | | Rest of | | and | | | |
| By geographical area | UK | | Europe | | USA | | World | | eliminations | | Total | |
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| Sales and other operating revenues | | | | | | | | | | | | |
| Segment sales and other operating revenues | 105,518 | | 76,768 | | 99,935 | | 71,547 | | – | | 353,768 | |
| Less: sales between areas | (50,942 | ) | (14,821 | ) | (5,032 | ) | (17,067 | ) | – | | (87,862 | ) |
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| Third party sales | 54,576 | | 61,947 | | 94,903 | | 54,480 | | – | | 265,906 | |
| Equity-accounted earnings | 5 | | 13 | | 127 | | 3,850 | | – | | 3,995 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment revenues | 54,581 | | 61,960 | | 95,030 | | 58,330 | | – | | 269,901 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment results | | | | | | | | | | | | |
| Profit (loss) before interest and tax from continuing operations | 5,897 | | 3,282 | | 11,664 | | 14,815 | | – | | 35,658 | |
| Finance costs and other finance (expense) income | 43 | | (262 | ) | (331 | ) | 34 | | – | | (516 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 5,940 | | 3,020 | | 11,333 | | 14,849 | | – | | 35,142 | |
| Taxation | (3,158 | ) | (1,176 | ) | (3,738 | ) | (4,444 | ) | – | | (12,516 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year from continuing operations | 2,782 | | 1,844 | | 7,595 | | 10,405 | | – | | 22,626 | |
| Profit (loss) from Innovene operations | 31 | | (76 | ) | (2 | ) | 22 | | – | | (25 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year | 2,813 | | 1,768 | | 7,593 | | 10,427 | | – | | 22,601 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Assets and liabilities | | | | | | | | | | | | |
| Segment assets | 49,018 | | 28,059 | | 78,586 | | 69,479 | | (8,085 | ) | 217,057 | |
| Tax receivable | 13 | | 65 | | 450 | | 16 | | – | | 544 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets | 49,031 | | 28,124 | | 79,036 | | 69,495 | | (8,085 | ) | 217,601 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Includes | | | | | | | | | | | | |
| Equity-accounted investments | 78 | | 1,538 | | 1,529 | | 17,904 | | – | | 21,049 | |
| Segment liabilities | (26,048 | ) | (18,484 | ) | (32,979 | ) | (17,949 | ) | 8,085 | | (87,375 | ) |
| Current tax payable | (757 | ) | (570 | ) | 11 | | (1,319 | ) | – | | (2,635 | ) |
| Finance debt | (12,666 | ) | (328 | ) | (7,201 | ) | (3,815 | ) | – | | (24,010 | ) |
| Deferred tax liabilities | (3,335 | ) | (938 | ) | (9,946 | ) | (3,897 | ) | – | | (18,116 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total liabilities | (42,806 | ) | (20,320 | ) | (50,115 | ) | (26,980 | ) | 8,085 | | (132,136 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other segment information | | | | | | | | | | | | |
| Capital expenditure and acquisitions | | | | | | | | | | | | |
| Intangible assets | 421 | | 53 | | 905 | | 723 | | – | | 2,102 | |
| Property, plant and equipment | 1,120 | | 916 | | 5,531 | | 5,962 | | – | | 13,529 | |
| Other | 46 | | 22 | | 156 | | 1,376 | | – | | 1,600 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total | 1,587 | | 991 | | 6,592 | | 8,061 | | – | | 17,231 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Depreciation, depletion and amortization | 2,139 | | 840 | | 3,459 | | 2,690 | | – | | 9,128 | |
| Exploration expense | 20 | | – | | 633 | | 392 | | – | | 1,045 | |
| Impairment losses | – | | 171 | | 114 | | 176 | | – | | 461 | |
| Impairment reversals | 176 | | – | | 90 | | 74 | | – | | 340 | |
| Loss on remeasurement to fair value less costs to sell and on disposal of | | | | | | | | | | | | |
| Innovene operations | 185 | | 36 | | (16 | ) | (21 | ) | – | | 184 | |
| Losses on sale of businesses and fixed assets | 12 | | 96 | | 217 | | 103 | | – | | 428 | |
| Gains on sale of businesses and fixed assets | 337 | | 577 | | 2,530 | | 270 | | – | | 3,714 | |
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|
Back to Contents
7 Segmental analysiscontinued
| | | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | Consolidation | | | |
| | | | | | | | | | adjustment | | | |
| | | | Rest of | | | | Rest of | | and | | | |
| By geographical area | UK | | Europe | | USA | | World | | eliminations | | Total | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sales and other operating revenues | | | | | | | | | | | | |
| Segment sales and other operating revenues | 95,375 | | 72,972 | | 101,190 | | 60,314 | | – | | 329,851 | |
| Less: sales attributable to Innovene operations | (2,610 | ) | (8,667 | ) | (4,309 | ) | (686 | ) | – | | (16,272 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment revenues from continuing operations | 92,765 | | 64,305 | | 96,881 | | 59,628 | | – | | 313,579 | |
| Less: sales between areas | (38,081 | ) | (5,013 | ) | (2,362 | ) | (16,541 | ) | – | | (61,997 | ) |
| Less: sales by continuing operations to Innovene | (5,599 | ) | (4,640 | ) | (1,508 | ) | (43 | ) | – | | (11,790 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Third party sales of continuing operations | 49,085 | | 54,652 | | 93,011 | | 43,044 | | – | | 239,792 | |
| Equity-accounted earnings | (8 | ) | 18 | | 86 | | 3,447 | | – | | 3,543 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment revenues | 49,077 | | 54,670 | | 93,097 | | 46,491 | | – | | 243,335 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment results | | | | | | | | | | | | |
| Profit before interest and tax from continuing operations | 1,167 | | 5,206 | | 12,639 | | 13,170 | | – | | 32,182 | |
| Finance costs and other finance expense | (80 | ) | (268 | ) | (366 | ) | (47 | ) | – | | (761 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 1,087 | | 4,938 | | 12,273 | | 13,123 | | – | | 31,421 | |
| Taxation | (289 | ) | (1,646 | ) | (3,798 | ) | (3,555 | ) | – | | (9,288 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year from continuing operations | 798 | | 3,292 | | 8,475 | | 9,568 | | – | | 22,133 | |
| Profit (loss) from Innovene operations | 234 | | 109 | | (165 | ) | 6 | | – | | 184 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year | 1,032 | | 3,401 | | 8,310 | | 9,574 | | – | | 22,317 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Assets and liabilities | | | | | | | | | | | | |
| Segment assets | 44,007 | | 26,560 | | 79,838 | | 64,129 | | (7,832 | ) | 206,702 | |
| Tax receivable | 2 | | 158 | | 6 | | 46 | | – | | 212 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets | 44,009 | | 26,718 | | 79,844 | | 64,175 | | (7,832 | ) | 206,914 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Includes | | | | | | | | | | | | |
| Equity-accounted investments | 74 | | 1,496 | | 1,420 | | 16,783 | | – | | 19,773 | |
| Segment liabilities | (25,079 | ) | (16,824 | ) | (34,146 | ) | (18,553 | ) | 7,832 | | (86,770 | ) |
| Current tax payable | (798 | ) | (1,057 | ) | (678 | ) | (1,741 | ) | – | | (4,274 | ) |
| Finance debt | (9,706 | ) | (433 | ) | (6,159 | ) | (2,864 | ) | – | | (19,162 | ) |
| Deferred tax liabilities | (2,223 | ) | (936 | ) | (9,400 | ) | (3,699 | ) | – | | (16,258 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total liabilities | (37,806 | ) | (19,250 | ) | (50,383 | ) | (26,857 | ) | 7,832 | | (126,464 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other segment information | | | | | | | | | | | | |
| Capital expenditure and acquisitions | | | | | | | | | | | | |
| Intangible assets | 205 | | 43 | | 579 | | 654 | | – | | 1,481 | |
| Property, plant and equipment | 1,340 | | 919 | | 4,804 | | 4,702 | | – | | 11,765 | |
| Other | 53 | | 18 | | 86 | | 746 | | – | | 903 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total | 1,598 | | 980 | | 5,469 | | 6,102 | | – | | 14,149 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Depreciation, depletion and amortization | 2,080 | | 932 | | 3,685 | | 2,074 | | – | | 8,771 | |
| Exploration expense | 32 | | 2 | | 425 | | 225 | | – | | 684 | |
| Impairment losses | 53 | | 7 | | 238 | | 61 | | – | | 359 | |
| Loss on remeasurement to fair value less costs to sell and on disposal of | | | | | | | | | | | | |
| Innovene operations | 24 | | 273 | | 262 | | 32 | | – | | 591 | |
| Losses on sale of businesses and fixed assets | – | | 37 | | 8 | | 64 | | – | | 109 | |
| Gains on sale of businesses and fixed assets | 107 | | 1,017 | | 282 | | 132 | | – | | 1,538 | |
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Back to Contents
7 Segmental analysiscontinued
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2004 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | Rest of | | | | Rest of | | | |
| By geographical area | UK | | Europe | | USA | | World | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Sales and other operating revenues | | | | | | | | | | |
| Segment sales and other operating revenues | 59,615 | | 52,540 | | 86,358 | | 48,534 | | 247,047 | |
| Less: sales attributable to Innovene operations | (2,365 | ) | (7,682 | ) | (4,109 | ) | (672 | ) | (14,828 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Segment revenues from continuing operations | 57,250 | | 44,858 | | 82,249 | | 47,862 | | 232,219 | |
| Less: sales between areas | (18,846 | ) | (1,396 | ) | (1,539 | ) | (10,188 | ) | (31,969 | ) |
| Less: sales by continuing operations to Innovene | (5,263 | ) | (896 | ) | (2,064 | ) | (3 | ) | (8,226 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Third party sales of continuing operations | 33,141 | | 42,566 | | 78,646 | | 37,671 | | 192,024 | |
| Equity-accounted income | 9 | | 17 | | 92 | | 2,162 | | 2,280 | |
|
|
|
|
|
|
|
|
|
|
|
| Segment revenues | 33,150 | | 42,583 | | 78,738 | | 39,833 | | 194,304 | |
|
|
|
|
|
|
|
|
|
|
|
| Segment results | | | | | | | | | | |
| Profit before interest and tax from continuing operations | 2,875 | | 3,121 | | 9,725 | | 10,025 | | 25,746 | |
| Finance costs and other finance (expense) income | 155 | | (261 | ) | (513 | ) | (161 | ) | (780 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 3,030 | | 2,860 | | 9,212 | | 9,864 | | 24,966 | |
| Taxation | (1,745 | ) | (779 | ) | (2,596 | ) | (1,962 | ) | (7,082 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year from continuing operations | 1,285 | | 2,081 | | 6,616 | | 7,902 | | 17,884 | |
| Loss from Innovene operations | (327 | ) | (110 | ) | (96 | ) | (89 | ) | (622 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year | 958 | | 1,971 | | 6,520 | | 7,813 | | 17,262 | |
|
|
|
|
|
|
|
|
|
|
|
| Other segment information | | | | | | | | | | |
| Depreciation, depletion and amortization | 2,030 | | 930 | | 3,906 | | 1,663 | | 8,529 | |
| Exploration expense | 26 | | 25 | | 361 | | 225 | | 637 | |
| Impairment losses | – | | – | | 570 | | 41 | | 611 | |
| Impairment reversals | – | | – | | – | | 31 | | 31 | |
| Losses on sale of businesses and fixed assets | 282 | | – | | 177 | | 320 | | 779 | |
| Gains on sale of businesses and fixed assets | – | | – | | 133 | | 1,552 | | 1,685 | |
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|
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|
Back to Contents
8 Earnings from jointly controlled entities and associates
| | | | | | | | | | $ million | |
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|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
| | Profit (loss) | | | | | | | | | |
| | before | | | | | | | | | |
| | interest | | | | | | Minority | | Profit (loss) | |
| By business | and tax | | Interest | | Tax | | interest | | for the year | |
|
|
|
|
|
|
|
|
|
|
|
| Exploration and Productiona | 5,838 | | 324 | | 1,804 | | 193 | | 3,517 | |
| Refining and Marketing | 487 | | 79 | | 67 | | – | | 341 | |
| Gas, Power and Renewables | 179 | | 21 | | 20 | | – | | 138 | |
| Other businesses and corporate | (1 | ) | – | | – | | – | | (1 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | 6,503 | | 424 | | 1,891 | | 193 | | 3,995 | |
|
|
|
|
|
|
|
|
|
|
|
| Earnings from jointly controlled entities | 5,834 | | 361 | | 1,727 | | 193 | | 3,553 | |
| Earnings from associates | 669 | | 63 | | 164 | | – | | 442 | |
|
|
|
|
|
|
|
|
|
|
|
| | 6,503 | | 424 | | 1,891 | | 193 | | 3,995 | |
|
|
|
|
|
|
|
|
|
|
|
| a | Includes a net gain of $892 million on the disposal of fixed assets. |
| | | | | | | | | | | |
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| | Profit (loss) | | | | | | | | | |
| | before interest | | | | | | Minority | | Profit (loss) | |
| By business | and tax | | Interest | | Tax | | interest | | for the year | |
|
|
|
|
|
|
|
|
|
|
|
| Exploration and Productionb | 4,813 | | 227 | | 1,250 | | 104 | | 3,232 | |
| Refining and Marketing | 385 | | 55 | | 81 | | – | | 249 | |
| Gas, Power and Renewables | 77 | | 7 | | 8 | | – | | 62 | |
| Other businesses and corporate | (14 | ) | – | | – | | – | | (14 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | 5,261 | | 289 | | 1,339 | | 104 | | 3,529 | |
| Innovene operations | 14 | | – | | – | | – | | 14 | |
|
|
|
|
|
|
|
|
|
|
|
| Continuing operations | 5,275 | | 289 | | 1,339 | | 104 | | 3,543 | |
|
|
|
|
|
|
|
|
|
|
|
| Earnings from jointly controlled entities | 4,615 | | 232 | | 1,196 | | 104 | | 3,083 | |
| Earnings from associates | 660 | | 57 | | 143 | | – | | 460 | |
|
|
|
|
|
|
|
|
|
|
|
| | 5,275 | | 289 | | 1,339 | | 104 | | 3,543 | |
|
|
|
|
|
|
|
|
|
|
|
| b | Includes a net gain of $270 million on the disposal of fixed assets. |
| | | | | | | | | | | |
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2004 | |
|
|
|
|
|
|
|
|
|
|
|
| | Profit (loss) | | | | | | | | | |
| | before interest | | | | | | Minority | | Profit (loss) | |
| By business | and tax | | Interest | | Tax | | interest | | for the year | |
|
|
|
|
|
|
|
|
|
|
|
| Exploration and Production | 3,244 | | 189 | | 1,029 | | 43 | | 1,983 | |
| Refining and Marketing | 360 | | 19 | | 79 | | – | | 262 | |
| Gas, Power and Renewables | 44 | | 7 | | 2 | | – | | 35 | |
| Other businesses and corporate | (9 | ) | 3 | | – | | – | | (12 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | 3,639 | | 218 | | 1,110 | | 43 | | 2,268 | |
| Innovene operations | 9 | | (3 | ) | – | | – | | 12 | |
|
|
|
|
|
|
|
|
|
|
|
| Continuing operations | 3,648 | | 215 | | 1,110 | | 43 | | 2,280 | |
|
|
|
|
|
|
|
|
|
|
|
| Earnings from jointly controlled entities | 3,017 | | 167 | | 989 | | 43 | | 1,818 | |
| Earnings from associates | 631 | | 48 | | 121 | | – | | 462 | |
|
|
|
|
|
|
|
|
|
|
|
| | 3,648 | | 215 | | 1,110 | | 43 | | 2,280 | |
|
|
|
|
|
|
|
|
|
|
|
9 Interest and other revenues
| | | | | | $ million | |
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|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
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|
|
|
|
|
|
| Dividends | 5 | | 52 | | 37 | |
| Interest from loans and other investments | 154 | | 73 | | 34 | |
| Other interest | 314 | | 324 | | 244 | |
| Miscellaneous income | 228 | | 240 | | 358 | |
|
|
|
|
|
|
|
| | 701 | | 689 | | 673 | |
| Innovene operations | – | | (76 | ) | (58 | ) |
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|
|
|
|
|
|
| Continuing operations | 701 | | 613 | | 615 | |
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|
Back to Contents
10 Gains on sale of businesses and fixed assets
| | | | | | $ million | |
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|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Gains on sale of businesses | | | | | | |
| Refining and Marketing | 104 | | 18 | | – | |
| Other businesses and corporate | 63 | | – | | – | |
|
|
|
|
|
|
|
| | 167 | | 18 | | – | |
|
|
|
|
|
|
|
| Gains on sale of fixed assets | | | | | | |
| Exploration and Production | 2,309 | | 1,198 | | 162 | |
| Refining and Marketing | 1,008 | | 223 | | 104 | |
| Gas, Power and Renewables | 193 | | 55 | | 56 | |
| Other businesses and corporate | 37 | | 47 | | 1,365 | |
|
|
|
|
|
|
|
| | 3,547 | | 1,523 | | 1,687 | |
|
|
|
|
|
|
|
| | 3,714 | | 1,541 | | 1,687 | |
| Innovene operations | – | | (3 | ) | (2 | ) |
|
|
|
|
|
|
|
| Continuing operations | 3,714 | | 1,538 | | 1,685 | |
|
|
|
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|
|
|
The principal transactions giving rise to these gains for each business segment are described below.
Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. The major divestments during 2006 that resulted in gains were the sales of our interest in the Shenzi discovery in the Gulf of Mexico in the US and interests in the North Sea. In 2005 the major divestment was the sale of the group’s interest in the Ormen Lange field in Norway. BP also sold various oil and gas properties in Trinidad & Tobago, Canada and the Gulf of Mexico. For 2004, divestments included interests in oil and natural gas properties in Australia, Canada and the Gulf of Mexico.
Refining and Marketing
During 2006, the group divested its retail business in the Czech Republic and fixed assets including its shareholding in Zhenhai Refining and Chemicals Company in China, its shareholding in Eiffage, the French-based construction company, and pipeline assets. In 2005, the group divested a number of regional retail networks in the US. For 2004, divestments included the sale of the Cushing and other pipeline interests in the US and the churn of retail assets.
Gas, Power and Renewables
In 2006, the group divested its shareholding in Enagas. In 2005, transactions included the disposal of the group’s interest in the Interconnector pipeline and power plant at Great Yarmouth in the UK. During 2004, the group divested its interest in two natural gas liquids plants in Canada.
Other businesses and corporate
In 2006, the group disposed of its ethylene oxide business. For 2004, the major disposals were the divestment of the group’s investments in PetroChina and Sinopec.
Additional information on the sale of businesses and fixed assets is given in Note 6.
11 Production and similar taxes
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| UK | 260 | | 495 | | 335 | |
| Overseas | 3,361 | | 2,515 | | 1,814 | |
|
|
|
|
|
|
|
| | 3,621 | | 3,010 | | 2,149 | |
|
|
|
|
|
|
|
Back to Contents
12 Depreciation, depletion and amortization
| | | | | | $ million | |
|
|
|
|
|
|
|
| By business | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Exploration and Production | | | | | | |
| UK | 1,720 | | 1,663 | | 1,642 | |
| Rest of Europe | 223 | | 228 | | 184 | |
| USA | 2,236 | | 2,426 | | 2,407 | |
| Rest of World | 2,354 | | 1,716 | | 1,350 | |
|
|
|
|
|
|
|
| | 6,533 | | 6,033 | | 5,583 | |
|
|
|
|
|
|
|
| Refining and Marketing | | | | | | |
| UKa | 303 | | 316 | | 318 | |
| Rest of Europe | 603 | | 687 | | 645 | |
| USA | 1,048 | | 1,082 | | 1,238 | |
| Rest of World | 290 | | 297 | | 331 | |
|
|
|
|
|
|
|
| | 2,244 | | 2,382 | | 2,532 | |
|
|
|
|
|
|
|
| Gas, Power and Renewables | | | | | | |
| UK | 18 | | 47 | | 37 | |
| Rest of Europe | 13 | | 20 | | 24 | |
| USA | 117 | | 109 | | 88 | |
| Rest of World | 44 | | 59 | | 69 | |
|
|
|
|
|
|
|
| | 192 | | 235 | | 218 | |
|
|
|
|
|
|
|
| Other businesses and corporate | | | | | | |
| UK | 98 | | 203 | | 251 | |
| Rest of Europe | 1 | | 130 | | 204 | |
| USA | 58 | | 187 | | 199 | |
| Rest of World | 2 | | 13 | | 25 | |
|
|
|
|
|
|
|
| | 159 | | 533 | | 679 | |
|
|
|
|
|
|
|
| By geographical area | | | | | | |
|
|
|
|
|
|
|
| UKa | 2,139 | | 2,229 | | 2,248 | |
| Rest of Europe | 840 | | 1,065 | | 1,057 | |
| USA | 3,459 | | 3,804 | | 3,932 | |
| Rest of World | 2,690 | | 2,085 | | 1,775 | |
|
|
|
|
|
|
|
| | 9,128 | | 9,183 | | 9,012 | |
| Innovene operations | – | | (412 | ) | (483 | ) |
|
|
|
|
|
|
|
| Continuing operations | 9,128 | | 8,771 | | 8,529 | |
|
|
|
|
|
|
|
| a | UK area includes the UK-based international activities of Refining and Marketing. |
Back to Contents
13 Impairment and losses on sale of businesses and fixed assets
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Impairment losses | | | | | | |
| Exploration and Production | 137 | | 266 | | 435 | |
| Refining and Marketing | 155 | | 93 | | 195 | |
| Gas, Power and Renewables | 100 | | – | | – | |
| Other businesses and corporate | 69 | | 59 | | 891 | |
|
|
|
|
|
|
|
| | 461 | | 418 | | 1,521 | |
|
|
|
|
|
|
|
| Impairment reversals | | | | | | |
| Exploration and Production | (340 | ) | – | | (31 | ) |
|
|
|
|
|
|
|
| | (340 | ) | – | | (31 | ) |
|
|
|
|
|
|
|
| Loss on sale of businesses or termination of operations | | | | | | |
| Refining and Marketing | – | | – | | 279 | |
| Other businesses and corporate | – | | – | | 416 | |
|
|
|
|
|
|
|
| | – | | – | | 695 | |
|
|
|
|
|
|
|
| Loss on sale of fixed assets | | | | | | |
| Exploration and Production | 195 | | 39 | | 227 | |
| Refining and Marketing | 228 | | 64 | | 92 | |
| Other businesses and corporate | 5 | | 6 | | – | |
|
|
|
|
|
|
|
| | 428 | | 109 | | 319 | |
| Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations | 184 | | 591 | | – | |
|
|
|
|
|
|
|
| | 733 | | 1,118 | | 2,504 | |
| Innovene operations | (184 | ) | (650 | ) | (1,114 | ) |
|
|
|
|
|
|
|
| Continuing operations | 549 | | 468 | | 1,390 | |
|
|
|
|
|
|
|
Impairment
In assessing whether a write-down is required in the carrying value of a potentially impaired asset, its carrying value is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair value less costs to sell and value in use. Given the nature of the group’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing the impairment charges described below is value in use. The group generally estimates value in use using a discounted cash flow model. The future cash flows are usually adjusted for risks specific to the asset and discounted using a pre-tax discount rate of 10% (2005 10% and 2004 9%). This discount rate is derived from the group’s post-tax weighted average cost of capital. A different pre-tax discount rate is used where the tax rate applicable to the asset is significantly different from the average corporate tax rate applicable to the group as a whole.
Exploration and Production
During 2006, Exploration and Production recognized a net gain on impairment. The main element was a $340 million credit for reversals of previously booked impairments relating to the UK North Sea, US Lower 48 and China. These reversals resulted from a positive change in the estimates used to determine the assets’ recoverable amount since the impairment losses were recognised. This was partially offset by impairment losses totalling $137 million. The major element was a charge of $109 million against intangible assets relating to properties in Alaska. The trigger for the impairment test was the decision of the Alaska Department of Natural Resources to terminate the Point Thompson Unit Agreement. We are defending our right through the appeal process. The remaining $28 million relates to other individually insignificant impairments, the impairment tests for which were triggered by downward reserves revisions and increased tax burden.
During 2005, Exploration and Production recognized total charges of $266 million for impairment in respect of producing oil and gas properties. The major element of this was a charge of $226 million relating to fields in the Shelf and Coastal areas of the Gulf of Mexico. The triggers for the impairment tests were primarily the effect of Hurricane Rita, which extensively damaged certain offshore and onshore production facilities, leading to repair costs and higher estimates of the eventual cost of decommissioning the production facilities and, in addition, reduced estimates of the quantities of hydrocarbons recoverable from some of these fields. The recoverable amount was based on management’s estimate of fair value less costs to sell consistent with recent transactions in the area. The remainder related to fields in the UK North Sea, which were tested for impairment following a review of the economic performance of these assets. During 2004, as a result of impairment triggers, reviews were conducted which resulted in impairment charges of $83 million in respect of King’s Peak in the Gulf of Mexico, $20 million in respect of two fields in the Gulf of Mexico Shelf Matagorda Island area and $184 million in respect of various US onshore fields. A charge of $88 million was reflected in respect of a gas processing plant in the US and a charge of $60 million following the blow-out of the Temsah platform in Egypt. In addition, following the lapse of the sale agreement for oil and gas properties in Venezuela, $31 million of the previously booked impairment charge was released.
Refining and Marketing
During 2006, certain assets in our Retail and Aromatics and Acetyls businesses were written down to fair value less costs to sell. During 2005, certain retail assets were written down to fair value less costs to sell. With the formation of Olefins and Derivatives at the end of 2004 certain agreements and assets were restructured to reflect the arm’s-length relationship that would exist in the future. This resulted in an impairment of the petrochemical facilities at Hull, UK.
Gas, Power and Renewables
The impairment charge for 2006 relates to certain North American pipeline assets. The trigger for impairment testing was the reduction in future pipeline tariff revenues and increased on-going operational costs.
Back to Contents
13 Impairment and losses on sale of businesses and fixed assets continued
Other businesses and corporate
The impairment charge for 2006 relates to remaining chemical assets after the sale of Innovene. The impairment charge for 2005 relates to the write-off of additional goodwill on the Solvay transactions. In 2004, in connection with the Solvay transactions, the group recognized impairment charges of $325 million for goodwill and $270 million for property, plant and equipment in BP Solvay Polyethylene Europe. As part of a restructuring of the North American Olefins and Derivatives businesses, decisions were taken to exit certain businesses and facilities, resulting in impairments and write-downs of $294 million.
Loss on sale of businesses or termination of operations
The principal transactions that give rise to the losses for each business segment are described below.
Refining and Marketing
In 2004, activities included the closure of two manufacturing plants at Hull, UK, which produced acids; the sale of the European speciality intermediate chemicals business; the closure of the lubricants operation of the Coryton refinery in the UK and of refining operations at the ATAS refinery in Mersin, Turkey.
Other businesses and corporate
For 2004, activities included the sale of the US speciality intermediate chemicals business; the sale of the fabrics and fibres business; and the closure of the linear alpha-olefins production facility at Pasadena, Texas.
Loss on sale of fixed assets
The principal transactions that give rise to the losses for each business segment are described below.
Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. For 2006, the largest component of the loss is attributed to the sale of properties in the Gulf of Mexico Shelf which includes increases in decommissioning liability estimates associated with the hurricane-damaged fields which were divested during the year. For 2004, this included interests in oil and natural gas properties in Indonesia and the Gulf of Mexico.
Refining and Marketing
For 2006, the principal transactions contributing to the loss were retail churn. For 2004, the principal transactions contributing to the loss were divestment of the Singapore refinery and retail churn.
14 Impairment of goodwill
| | | | $ million | |
|
|
|
|
|
| Goodwill at 31 December | 2006 | | 2005 | |
|
|
|
|
|
| Exploration and Production | 4,282 | | 4,371 | |
| Refining and Marketing | 6,390 | | 5,955 | |
| Gas, Power and Renewables | 108 | | 45 | |
|
|
|
|
|
| | 10,780 | | 10,371 | |
|
|
|
|
|
Goodwill acquired through business combinations has been allocated first to business segments and then down to the next level of cash-generating unit that is expected to benefit from the synergies of the acquisition. For Exploration and Production, goodwill has been allocated to each geographic region, that is UK, Rest of Europe, US and Rest of World, and for Refining and Marketing, goodwill has been allocated to strategic performance units (SPUs), namely Refining, Retail, Lubricants, Aromatics and Acetyls and Business Marketing.
In assessing whether goodwill has been impaired, the carrying amount of the cash-generating unit (including goodwill) is compared with the recoverable amount of the cash-generating unit. The recoverable amount is the higher of fair value less costs to sell and value in use. In the absence of any information about the fair value of a cash-generating unit, the recoverable amount is deemed to be the value in use.
The group generally estimates value in use using a discounted cash flow model. The future cash flows are usually adjusted for risks specific to the asset and discounted using a pre-tax discount rate of 10% (2005 10%). This discount rate is derived from the group’s post-tax weighted average cost of capital. A different pre-tax discount rate is used where the tax rate applicable to the region is significantly different from the average corporate tax rate applicable to the group as a whole.
The four or five year business segment plans, which are approved on an annual basis by senior management, are the source for information for the determination of the various values in use. They contain implicit forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step to the preparation of these plans, various environmental assumptions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates, are set by senior management. These environmental assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability.
For the purposes of impairment testing, the group’s Brent oil price assumption is an average $65 per barrel in 2007, $68 per barrel in 2008, $67 per barrel in 2009, $66 per barrel in 2010, $64 per barrel in 2011 and $40 per barrel in 2012 and beyond (2005 $55 per barrel in 2005 decreasing in equal annual steps over the following three years to $25 per barrel in 2009 and beyond). Similarly, the group’s assumption for Henry Hub natural gas prices is an average of $8.10 per mmBtu in 2007, $8.31 per mmBtu in 2008, $7.88 per mmBtu in 2009, $8.21 per mmBtu in 2010, $7.50 per mmBtu in 2011 and $5.50 per mmBtu in 2012 and beyond (2005 $8.65 per mmBtu in 2005 decreasing in equal annual steps over the following three years to $4.00 per mmBtu in 2009 and beyond). These prices are adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas.
Back to Contents
14 Impairment of goodwillcontinued
Exploration and Production
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of cessation of production of each producing field. The date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons, the production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic models and key assumptions agreed by BP’s management for the purpose. Cash outflows and hydrocarbon production quantities for the first five years are agreed as part of the annual planning process. Thereafter, estimated production quantities and cash outflows up to the date of cessation of production are developed to be consistent with this.
Consistent with prior years, the review for impairment was carried out during the fourth quarter of 2006 using data which was appropriate at that time. As permitted by IAS 36, the detailed calculation made in 2005 was used for the 2006 impairment test on the goodwill allocated to the Rest of World as the criteria of IAS 36 were considered to be satisfied in respect of this region: the excess of the recoverable amount over the carrying amount was substantial in 2005; there had been no significant change in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount at the time of the test was remote. Therefore, the detailed impairment test for goodwill was reperformed only on the carrying amounts in the UK and the US.
The following table shows the carrying value of the goodwill allocated to each of the regions of the Exploration and Production segment and the amount by which the recoverable amount (value in use) exceeds the carrying amount of the goodwill and other non-current assets in the cash-generating units to which the goodwill has been allocated. No impairment charge is required.
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | Rest of | | | | Rest of | | | |
| | UK | | Europe | | USA | | World | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Goodwill | 341 | | – | | 3,426 | | 515 | | 4,282 | |
| Excess of recoverable amount over carrying amount | 7,886 | | n/a | | 28,856 | | n/a | | – | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | Rest of | | | | Rest of | | | |
| | UK | | Europe | | USA | | World | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Goodwill | 341 | | – | | 3,515 | | 515 | | 4,371 | |
| Excess of recoverable amount over carrying amount | 3,205 | | n/a | | 6,421 | | n/a | | – | |
|
|
|
|
|
|
|
|
|
|
|
The key assumptions required for the value-in-use estimation are the oil and natural gas prices, production volumes and the discount rate. To test the sensitivity of the excess of the recoverable amount over the carrying amount of goodwill and other non-current assets shown above (the headroom) to changes in production volumes and oil and natural gas prices, management has developed ‘rules of thumb’ for key assumptions. Applying these gives an indication of the impact on the headroom of possible changes in the key assumptions.
On the basis of the rules of thumb using estimated 2007 production profiles and an assumed average 15-year production life, it is estimated that the long-term price of Brent that would cause the total recoverable amount to be equal to the total carrying amount of the goodwill and related non-current assets for individual cash-generating units would be of the order of $31 per barrel for the UK and $28 per barrel for the US. No reasonably possible change in oil or gas prices would cause the headroom in the Rest of the World to be reduced to zero.
Estimated production volumes are based on detailed data for the fields and take into account development plans for the fields agreed by management as part of the long-term planning process. It is estimated that, if all our production were to be reduced by 10% for the whole of the next 15 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amounts of the individual cash generating units to zero. Consequently, management believes no reasonably possible change in the production assumption would cause the carrying amount of goodwill and other non-current assets to exceed their recoverable amount.
Management also believes that currently there is no reasonably possible change in discount rate which would reduce the group’s headroom to zero.
Refining and Marketing
For all cash generating units, the cash flows for the next four years are derived from the four-year business segment plan. The cost inflation rate is assumed to be 2.5% (2005 assumption was 2.5%) throughout the period. For determining the value in use for each of the SPUs, cash flows for a period of 10 years have been discounted and aggregated with its terminal value.
Refining
Cash flows beyond the four-year period are extrapolated using a 2% growth rate (2005 assumption was 2%).
The key assumptions to which the calculation of value in use for the Refining unit is most sensitive are gross margins, production volumes and the terminal value. The value assigned to the gross margin is based on a $7.25 per barrel global indicator margin (GIM), which is then adjusted for specific refinery configurations. In 2005 the value assigned to the gross margin was based on a $5.25 per barrel GIM, except in the first year of the plan period when a GIM of $7.25 was used, reflecting market conditions expected in the near term. The value assigned to the production volume is 850mmbbl a year (2005 900mmbbl) and remains constant over the plan period. The value assigned to the terminal value assumption is 6 times earnings (2005 5 times), which is indicative of similar assets in the current market. These key assumptions reflect past experience and are consistent with external sources.
Management believes that no reasonably possible change in the key assumptions would lead to the Refining value in use being equal to its carrying amount.
Back to Contents
14 Impairment of goodwillcontinued
Retail
Cash flows beyond the four-year period are extrapolated using a 1.3% growth rate (2005 assumption was no growth) reflecting a competitive marketplace within a growing global economy.
The key assumptions to which the calculation of value in use for the Retail unit is most sensitive are unit gross margins, branded marketing volumes, the terminal value and discount rate. The value assigned to the unit gross margin varies between markets. For the purpose of planning, each market develops a gross margin based upon a market-specific reference price adjusted for the different income streams within the market and other market specific factors. The weighted average Retail reference margin used in the plan was 5.0 cents per litre (2005 5.4 cents per litre). The value assigned to the branded marketing volume assumption is 100 billion litres a year (2005 101 billion litres a year). The unit gross margin assumptions decline on average by 5% a year over the plan period and marketing volume assumptions grow by an average of 5% a year over the plan period. The value assigned to the terminal value assumption is 6.5 times earnings (2005 6.5 times), which is indicative of similar assets in the current market. These key assumptions reflect past experience and are consistent with external sources.
The Retail unit’s recoverable amount exceeds its carrying amount by $2.1 billion. Based on sensitivity analysis, it is estimated that if there is an adverse change in the unit gross margin of 11%, the recoverable amount of the Retail unit would equal its carrying amount. It is estimated that, if the volume assumption changes by 5%, the Retail unit’s value in use changes by $1 billion and, if there is an adverse change in Retail volumes of 11 billion litres a year, the recoverable amount of the Retail unit would equal its carrying amount. If the multiple of earnings used in the terminal value changes by 1 then the Retail unit’s value in use changes by $0.7 billion and, if the multiple of earnings falls to 3 times then the Retail value in use would equal its carrying amount. A change of 1% in the discount rate would change the Retail value in use by $0.7 billion and, if the discount rate increases to 13%, the value in use of the Retail unit would equal its carrying amount.
Lubricants
Cash flows beyond the four-year period are extrapolated using a 3% margin growth rate (2005 assumption was 3%), which is lower than the long-term average growth rate for the first four years. The terminal value for the Lubricants unit represents cash flows discounted to perpetuity.
For the Lubricants unit, the key assumptions to which the calculation of value in use is most sensitive are operating margin, sales volumes and the discount rate. The average values assigned to the operating margins and sales volumes over the plan period are 53 cents per litre (2005 56 cents per litre) and 3.5 billion litres a year (2005 3.5 billion litres) respectively. These key assumptions reflect past experience.
The Lubricants unit’s recoverable amount exceeds its carrying amount by $2.0 billion. Based on sensitivity analysis, it is estimated that if there is an adverse change in the operating gross margin of 5 cents per litre, the recoverable amount of the Lubricants unit would equal its carrying amount. If the sales volume assumption changes by 5%, the Lubricants unit’s value in use changes by $1.1 billion and, if there is an adverse change in Lubricants sales volumes of 300 million litres a year, the recoverable amount of the Lubricants unit would equal its carrying amount. A change of 1% in the discount rate would change the Lubricants unit’s value in use by $0.6 billion and, if the discount rate increases to 14% the value in use of the Lubricants unit would equal its carrying amount.
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
| | Refining | | Retail | | Lubricants | | Other | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Goodwill | 1,328 | | 841 | | 4,098 | | 123 | | 6,390 | |
| Excess of recoverable amount over carrying amount | n/a | | 2,100 | | 2,012 | | n/a | | – | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | |
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| | Refining | | Retail | | Lubricants | | Other | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Goodwill | 1,388 | | 832 | | 3,612 | | 123 | | 5,955 | |
| Excess of recoverable amount over carrying amount | n/a | | 1,511 | | 3,953 | | n/a | | – | |
|
|
|
|
|
|
|
|
|
|
|
15 Distribution and administration expenses
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Distribution | 13,174 | | 13,187 | | 12,325 | |
| Administration | 1,273 | | 1,325 | | 1,284 | |
|
|
|
|
|
|
|
| | 14,447 | | 14,512 | | 13,609 | |
| Innovene operations | – | | (806 | ) | (841 | ) |
|
|
|
|
|
|
|
| Continuing operations | 14,447 | | 13,706 | | 12,768 | |
|
|
|
|
|
|
|
16 Currency exchange gains and losses
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Currency exchange losses charged to income | 222 | | 94 | | 55 | |
| Innovene operations | – | | (80 | ) | (13 | ) |
|
|
|
|
|
|
|
| Continuing operations | 222 | | 14 | | 42 | |
|
|
|
|
|
|
|
Back to Contents
17 Research
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Expenditure on research | 395 | | 502 | | 439 | |
| Innovene operations | – | | (128 | ) | (139 | ) |
|
|
|
|
|
|
|
| Continuing operations | 395 | | 374 | | 300 | |
|
|
|
|
|
|
|
18 Operating leases
The table below shows the expense for the year in respect of operating leases. Where an operating lease is entered into solely by the group as the operator of a jointly controlled asset, the total cost is included in this analysis, irrespective of any amounts that have been or will be reimbursed by joint venture partners. Where BP is not the operator of a jointly controlled asset, operating lease costs and minimum future lease payments are excluded from the information given below.
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Minimum lease payments | 3,660 | | 2,737 | | 2,442 | |
| Sub-lease rentals | (131 | ) | (114 | ) | (115 | ) |
|
|
|
|
|
|
|
| | 3,529 | | 2,623 | | 2,327 | |
| Innovene operations | – | | (49 | ) | (89 | ) |
|
|
|
|
|
|
|
| Continuing operations | 3,529 | | 2,574 | | 2,238 | |
|
|
|
|
|
|
|
The minimum future lease payments at 31 December (before deducting related rental income from operating sub-leases, for 2006 of $626 million, 2005 $718 million) were as follows:
| | | | | | $ million | |
|
|
|
|
|
|
|
| Minimum future lease payments | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Payable within | | | | | | |
| 1 year | 3,428 | | 2,610 | | 2,061 | |
| 2 to 5 years | 8,440 | | 6,584 | | 4,357 | |
| Thereafter | 5,684 | | 4,619 | | 3,341 | |
|
|
|
|
|
|
|
| | 17,552 | | 13,813 | | 9,759 | |
|
|
|
|
|
|
|
The following additional disclosures represent the net operating lease expense and net minimum future lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint venture partners. Where operating lease costs are incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. For 2006, $895 million of the cost for the year has been capitalized.
Where BP is not the operator of a jointly controlled asset, operating lease costs and minimum future lease payments are excluded from the information given below.
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Minimum lease payments | 2,937 | | 1,841 | | 1,840 | |
| Sub-lease rentals | (131 | ) | (110 | ) | (109 | ) |
|
|
|
|
|
|
|
| | 2,806 | | 1,731 | | 1,731 | |
| Innovene operations | – | | (49 | ) | (89 | ) |
|
|
|
|
|
|
|
| Continuing operations | 2,806 | | 1,682 | | 1,642 | |
|
|
|
|
|
|
|
| | | | | | $ million | |
|
|
|
|
|
|
|
| Minimum future lease payments | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Payable within | | | | | | |
| 1 year | 2,732 | | 1,643 | | 1,534 | |
| 2 to 5 years | 7,290 | | 4,666 | | 3,778 | |
| Thereafter | 5,221 | | 4,579 | | 3,275 | |
|
|
|
|
|
|
|
| | 15,243 | | 10,888 | | 8,587 | |
|
|
|
|
|
|
|
The group has entered into operating leases on ships, plant and machinery, commercial vehicles, land and buildings, including service station sites and office accommodation. The ship leases represent approximately 36% (2005 52%) of the minimum future lease payments. The typical durations of the leases are as follows:
| | Years | |
|
|
|
| Ships | up to 20 | |
| Plant and machinery | up to 10 | |
| Commercial vehicles | up to 15 | |
| Land and buildings | up to 40 | |
|
|
|
Back to Contents
18 Operating leases continued
Principal details of the leases are:
Ships: the group has entered into a number of structured operating leases for vessels, but which generally have no renewal or extension options. In most cases rentals vary with interest rates, but the amounts of these contingent rentals are not significant for the years presented. The group also routinely enters into bareboat charters, time charters and spot charters for ships on standard industry terms.
Plant and machinery: this principally comprises leases for drilling rigs. Generally these leases have no renewal options. There are no financial restrictions placed upon the lessee by entering into these leases.
Commercial vehicles: primarily railcar leases. Generally these leases have no renewal options. There are no financial restrictions placed upon the lessee by entering into these leases.
Land and buildings: the majority of these leases have no renewal options. There are no financial restrictions placed upon the lessee by entering into these leases.
The minimum future lease payments including executory costs associated with the leases of $482 million (after deducting related rental income from operating sub-leases of $626 million) were as follows:
| | $ million | |
|
|
|
| | 2006 | |
|
|
|
| 2007 | 3,355 | |
| 2008 | 3,031 | |
| 2009 | 2,403 | |
| 2010 | 1,686 | |
| 2011 | 1,191 | |
| Thereafter | 5,742 | |
|
|
|
| | 17,408 | |
|
|
|
19 Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of oil and natural gas resources. All such activity is recorded within the Exploration and Production segment.
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Exploration and evaluation costs | | | | | | |
| Exploration expenditure written off | 624 | | 305 | | 274 | |
| Other exploration costs | 421 | | 379 | | 363 | |
|
|
|
|
|
|
|
| Exploration expense for the year | 1,045 | | 684 | | 637 | |
|
|
|
|
|
|
|
| Intangible assets | 4,110 | | 4,008 | | 3,761 | |
|
|
|
|
|
|
|
| Net assets | 4,110 | | 4,008 | | 3,761 | |
|
|
|
|
|
|
|
| Capital expenditure | 1,537 | | 950 | | 754 | |
|
|
|
|
|
|
|
| Net cash used in operating activities | 421 | | 379 | | 363 | |
| Net cash used in investing activities | 1,498 | | 950 | | 754 | |
|
|
|
|
|
|
|
20 Auditors’ remuneration
| | | | | | $ million | |
|
|
|
|
|
|
|
| Fees – Ernst & Young | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Fees payable to the company’s auditors for the audit of the company’s accountsa | 15 | | 19 | | 13 | |
| Fees payable to the company’s auditors and its associates for other services | | | | | | |
| Audit of the company’s subsidiaries pursuant to legislation | 31 | | 34 | | 30 | |
| Other services pursuant to legislation | 15 | | 6 | | 7 | |
|
|
|
|
|
|
|
| | 61 | | 59 | | 50 | |
| | | | | | | |
| Tax services | 1 | | 10 | | 14 | |
| Services relating to corporate finance transactions | 2 | | 3 | | 7 | |
| All other services | 9 | | 23 | | 9 | |
| Audit fees in respect of the BP pension plans | – | | 1 | | 1 | |
|
|
|
|
|
|
|
| | 73 | | 96 | | 81 | |
| Innovene operations | – | | (9 | ) | (3 | ) |
|
|
|
|
|
|
|
| Continuing operations | 73 | | 87 | | 78 | |
|
|
|
|
|
|
|
| a | Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements. |
Total fees for 2006 include $5 million of additional fees for 2005 (2005 includes $4 million of additional fees for 2004). Auditors’ remuneration is included in the income statement within distribution and administration expenses.
The tax services relate to income tax and indirect tax compliance and employee tax services.
Back to Contents
20 Auditors’ remuneration continued
The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements and were pre-approved by the committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young compared to that of other potential service providers. These services are for a fixed term.
Fees paid to major firms of accountants other than Ernst & Young for other services amounted to $52 million (2005 $151 million and 2004 $82 million).
21 Finance costs
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Bank loans and overdrafts | 130 | | 44 | | 34 | |
| Other loans | 1,020 | | 828 | | 573 | |
| Finance leases | 46 | | 38 | | 37 | |
|
|
|
|
|
|
|
| Interest payable | 1,196 | | 910 | | 644 | |
| Capitalized at 5.25% (2005 4.25% and 2004 3%)a | (478 | ) | (351 | ) | (204 | ) |
| Early redemption of borrowings and finance leases | – | | 57 | | – | |
|
|
|
|
|
|
|
| | 718 | | 616 | | 440 | |
|
|
|
|
|
|
|
| a | Tax relief on capitalized interest is $182 million (2005 $123 million and 2004 $73 million). |
22 Other finance income and expense
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Interest on pension and other post-retirement benefit plan liabilities | 1,940 | | 2,022 | | 2,012 | |
| Expected return on pension and other post-retirement benefit plan assets | (2,410 | ) | (2,138 | ) | (1,983 | ) |
|
|
|
|
|
|
|
| Interest net of expected return on plan assets | (470 | ) | (116 | ) | 29 | |
| Unwinding of discount on provisions | 245 | | 201 | | 196 | |
| Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP | 23 | | 57 | | 91 | |
| Change in discount rate for provisionsa | – | | – | | 41 | |
|
|
|
|
|
|
|
| | (202 | ) | 142 | | 357 | |
| Innovene operations | – | | 3 | | (17 | ) |
|
|
|
|
|
|
|
| Continuing operations | (202 | ) | 145 | | 340 | |
|
|
|
|
|
|
|
| a | Revaluation of environmental and litigation and other provisions at a different discount rate. |
Back to Contents
23 Taxation
| | | | | | $ million | |
|
|
|
|
|
|
|
| Tax on profit | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Current tax | | | | | | |
| Charge for the year | 11,199 | | 10,511 | | 7,217 | |
| Adjustment in respect of prior years | 442 | | (977 | ) | (308 | ) |
|
|
|
|
|
|
|
| | 11,641 | | 9,534 | | 6,909 | |
| Innovene operations | 159 | | (910 | ) | (48 | ) |
|
|
|
|
|
|
|
| Continuing operations | 11,800 | | 8,624 | | 6,861 | |
|
|
|
|
|
|
|
| Deferred tax | | | | | | |
| Origination and reversal of temporary differences in the current year | 1,956 | | 164 | | 138 | |
| Adjustment in respect of prior years | (1,240 | ) | (450 | ) | (74 | ) |
|
|
|
|
|
|
|
| | 716 | | (286 | ) | 64 | |
| Innovene operations | – | | 950 | | 157 | |
|
|
|
|
|
|
|
| Continuing operations | 716 | | 664 | | 221 | |
|
|
|
|
|
|
|
| Tax on profit from continuing operations | 12,516 | | 9,288 | | 7,082 | |
|
|
|
|
|
|
|
| Tax on profit from continuing operations may be analysed as follows: | | | | | | |
|
|
|
|
|
|
|
| Current tax charge | | | | | | |
| UK | 2,657 | | 880 | | 1,839 | |
| Overseas | 9,143 | | 7,744 | | 5,022 | |
|
|
|
|
|
|
|
| | 11,800 | | 8,624 | | 6,861 | |
|
|
|
|
|
|
|
| Deferred tax charge | | | | | | |
| UK | 500 | | (489 | ) | (218 | ) |
| Overseas | 216 | | 1,153 | | 439 | |
|
|
|
|
|
|
|
| | 716 | | 664 | | 221 | |
|
|
|
|
|
|
|
| Total | | | | | | |
| UK | 3,157 | | 391 | | 1,621 | |
| Overseas | 9,359 | | 8,897 | | 5,461 | |
|
|
|
|
|
|
|
| | 12,516 | | 9,288 | | 7,082 | |
|
|
|
|
|
|
|
| | | | | | | |
| | | | | | $ million | |
|
|
|
|
|
|
|
| Tax included in statement of recognized income and expense | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Current tax | | | | | | |
| Current year tax charge | (51 | ) | 45 | | 23 | |
|
|
|
|
|
|
|
| | (51 | ) | 45 | | 23 | |
|
|
|
|
|
|
|
| Deferred tax | | | | | | |
| Origination and reversal of temporary differences in the current year | 985 | | 309 | | 50 | |
| Adjustment in respect of prior years | – | | (95 | ) | – | |
|
|
|
|
|
|
|
| | 985 | | 214 | | 50 | |
|
|
|
|
|
|
|
| Tax included in statement of recognized income and expense | 934 | | 259 | | 73 | |
|
|
|
|
|
|
|
| This comprises: | | | | | | |
|
|
|
|
|
|
|
| Currency translation differences | 201 | | (11 | ) | 208 | |
| Exchange gain on translation of foreign operations transferred to loss on sale of businesses | – | | (95 | ) | – | |
| Actuarial gain relating to pensions and other post-retirement benefits | 820 | | 356 | | (96 | ) |
| Share-based payments | (26 | ) | – | | (39 | ) |
| Net (gain) loss on revaluation of cash flow hedges | 47 | | (63 | ) | – | |
| Unrealized (gain) loss on available-for-sale financial assets | (108 | ) | 72 | | – | |
|
|
|
|
|
|
|
| Tax included in statement of recognized income and expense | 934 | | 259 | | 73 | |
|
|
|
|
|
|
|
Back to Contents
23 Taxation continued
Reconciliation of the effective tax rate
The following table provides a reconciliation of the UK statutory corporation tax rate to the effective tax rate of the group on profit before taxation from continuing operations.
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 35,142 | | 31,421 | | 24,966 | |
|
|
|
|
|
|
|
| Tax on profit from continuing operations | 12,516 | | 9,288 | | 7,082 | |
|
|
|
|
|
|
|
| Effective tax rate | 36 | % | 30 | % | 28 | % |
|
|
|
|
|
|
|
| | | |
| | % of profit before tax from continuing operations | |
|
|
|
|
|
|
|
| UK statutory corporation tax rate | 30 | | 30 | | 30 | |
| Increase (decrease) resulting from | | | | | | |
| UK supplementary and overseas taxes at higher rates | 11 | | 9 | | 8 | |
| Tax reported in equity-accounted entities | (3 | ) | (3 | ) | (3 | ) |
| Adjustments in respect of prior years | (2 | ) | (3 | ) | (1 | ) |
| Restructuring benefits | – | | (1 | ) | (2 | ) |
| Current year losses unrelieved (prior year losses utilized) | (1 | ) | (3 | ) | (3 | ) |
| Other | 1 | | 1 | | (1 | ) |
|
|
|
|
|
|
|
| Effective tax rate | 36 | | 30 | | 28 | |
|
|
|
|
|
|
|
| | | | | | | | | | | |
| Deferred tax | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | Income statement | | | | Balance sheet | |
|
|
|
|
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| Deferred tax liability | | | | | | | | | | |
| Depreciation | 1,484 | | (778 | ) | 492 | | 21,463 | | 18,529 | |
| Pension plan surplus | 173 | | 170 | | 10 | | 1,733 | | 957 | |
| Other taxable temporary differences | 417 | | 887 | | (113 | ) | 4,439 | | 3,864 | |
|
|
|
|
|
|
|
|
|
|
|
| | 2,074 | | 279 | | 389 | | 27,635 | | 23,350 | |
|
|
|
|
|
|
|
|
|
|
|
| Deferred tax asset | | | | | | | | | | |
| Petroleum revenue tax | 4 | | 121 | | 77 | | (457 | ) | (407 | ) |
| Pension plan and other post-retirement benefit plan deficits | 71 | | 220 | | 92 | | (1,824 | ) | (1,822 | ) |
| Decommissioning, environmental and other provisions | (615 | ) | (329 | ) | 106 | | (2,960 | ) | (2,218 | ) |
| Derivative financial instruments | (115 | ) | (629 | ) | – | | (974 | ) | (807 | ) |
| Tax credit and loss carry forward | 220 | | (245 | ) | 6 | | (662 | ) | (253 | ) |
| Other deductible temporary differences | (923 | ) | 297 | | (606 | ) | (2,642 | ) | (1,585 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | (1,358 | ) | (565 | ) | (325 | ) | (9,519 | ) | (7,092 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Net deferred tax liability | 716 | | (286 | ) | 64 | | 18,116 | | 16,258 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | |
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Analysis of movements during the year | | | | | | |
| At 1 January | 16,258 | | 16,701 | | 16,051 | |
| Adoption of IAS 32 and 39 | – | | (112 | ) | – | |
|
|
|
|
|
|
|
| Restated | 16,258 | | 16,589 | | 16,051 | |
| Exchange adjustments | 175 | | (178 | ) | 358 | |
| Charge for the year on ordinary activities | 716 | | (286 | ) | 64 | |
| Charge for the year in the statement of recognized income and expense | 985 | | 214 | | 50 | |
| Other movements | (18 | ) | (81 | ) | 178 | |
|
|
|
|
|
|
|
| At 31 December | 18,116 | | 16,258 | | 16,701 | |
|
|
|
|
|
|
|
| |
Factors that may affect future tax charges
The group earns income in many different countries and, on average, pays taxes at rates higher than the UK statutory rate. The overall impact of these higher taxes, which include the supplementary charge on UK North Sea profits, is subject to changes in enacted tax rates and the country mix of the group’s income. The current high oil price environment continues to create conditions that encourage host governments to review their fiscal regimes.
In 2006 the UK supplementary charge was raised to 20% increasing the group’s effective tax rate by 2%. The impact of the additional one-off deferred tax adjustment relating to this rate change ($460 million) was largely offset by utilization of relieving measures specifically provided in the legislation.
Under IFRS, the results of equity-accounted entities are reported within the group’s profit before taxation on a post-tax basis. The impact of this treatment in 2006 has been to reduce the reported effective tax rate by around 3%. This effect is expected to continue for the foreseeable future assuming similar income levels from the entities.
Going forward, the effective tax rate is expected to be around 37%.
At 31 December 2006, deferred tax liabilities were recognized for all taxable temporary differences: |
| – | Except where the deferred tax liability arises on goodwill that is not tax deductible or the initial recognition of an asset or liability in a transaction thatis not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss. |
| – | In respect of taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where thetiming of the reversal of the temporary differences can be controlled by the group and it is probable that the temporary differences will not reverse inthe foreseeable future. |
Back to Contents
23 Taxation continued
| At 31 December 2006, deferred tax assets were recognized for all deductible temporary differences, carry forward of unused tax assets and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax assets and unused tax losses can be utilized: |
| – | Except where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability ina transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss. |
| – | In respect of deductible temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, deferred taxassets are only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit willbe available against which the temporary differences can be utilized. |
The group has around $4.7 billion (2005 $5.1 billion and 2004 $7.7 billion) of carry-forward tax losses in the UK and Germany, which would be available to offset against future taxable income. These tax losses do not time expire. At the end of 2006, $216 million of deferred tax assets were recognized on these losses (2005 $176 million of assets and 2004 no tax assets were recognized). Tax assets are recognized only to the extent that it is considered more likely than not that suitable taxable income will arise. The group has not recognized any significant deferred tax assets in relation to carry forwards of losses in other taxing jurisdictions and this is not expected to have a material effect on the group’s tax rate in future years.
At the end of 2006, the group had around $2.0 billion (2005 $1.5 billion) of unused tax credits in the UK and the US, in respect of which no deferred tax assets have been recognized. In 2006, $828 million of tax credits were utilized (2005 $774 million).
The major components of temporary differences in the current year are tax depreciation, US inventory holding gains (classified under other taxable temporary differences) and provisions. |
24 Dividends
| | | pence per share | | | cents per share | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Dividends announced and paid | | | | | | | | | | | | | | | | | | |
| Preference shares | | | | | | | | | | | | | 2 | | 2 | | 2 | |
| Ordinary shares | | | | | | | | | | | | | | | | | | |
| March | 5.288 | | 4.522 | | 3.674 | | 9.375 | | 8.500 | | 6.750 | | 1,922 | | 1,823 | | 1,492 | |
| June | 5.251 | | 4.450 | | 3.807 | | 9.375 | | 8.500 | | 6.750 | | 1,893 | | 1,808 | | 1,477 | |
| September | 5.324 | | 5.119 | | 3.860 | | 9.825 | | 8.925 | | 7.100 | | 1,943 | | 1,871 | | 1,536 | |
| December | 5.241 | | 5.061 | | 3.910 | | 9.825 | | 8.925 | | 7.100 | | 1,926 | | 1,855 | | 1,534 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | 21.104 | | 19.152 | | 15.251 | | 38.400 | | 34.850 | | 27.700 | | 7,686 | | 7,359 | | 6,041 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Dividend announced per ordinary share, | | | | | | | | | | | | | | | | | | |
| payable in March 2007 | 5.258 | | – | | – | | 10.325 | | – | | – | | 1,999 | | – | | – | |
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
The group does not account for dividends until they have been paid. The accounts for the year ended 31 December 2006 do not reflect the dividend announced on 6 February 2007 and payable in March 2007; this will be treated as an appropriation of profit in the year ended 31 December 2007.
Back to Contents
25 Earnings per ordinary share
| | | | | | cents per share | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Basic earnings per share | 111.41 | | 104.25 | | 78.24 | |
| Diluted earnings per share | 110.56 | | 103.05 | | 76.87 | |
|
|
|
|
|
|
|
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year. The average number of shares outstanding excludes treasury shares and the shares held by the Employee Share Ownership Plans.
For the diluted earnings per share calculation, the profit attributable to ordinary shareholders is adjusted for the unwinding of the discount on the deferred consideration for the acquisition of our interest in TNK-BP. The weighted average number of shares outstanding during the year is adjusted for the number of shares to be issued for the deferred consideration for the acquisition of our interest in TNK-BP and the number of shares that would be issued on conversion of outstanding share options into ordinary shares using the treasury stock method.
| | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Profit from continuing operations attributable to BP shareholders | 22,340 | | 21,842 | | 17,697 | |
| Less dividend requirements on preference shares | 2 | | 2 | | 2 | |
|
|
|
|
|
|
|
| Profit from continuing operations attributable to BP ordinary shareholders | 22,338 | | 21,840 | | 17,695 | |
| Profit (loss) from discontinued operations | (25 | ) | 184 | | (622 | ) |
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| | 22,313 | | 22,024 | | 17,073 | |
| Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP (net of tax) | 16 | | 40 | | 64 | |
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| Diluted profit for the year attributable to BP ordinary shareholders | 22,329 | | 22,064 | | 17,137 | |
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| | | | | | shares thousand | |
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| | 2006 | | 2005 | | 2004 | |
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| Basic weighted average number of ordinary shares | 20,027,527 | | 21,125,902 | | 21,820,535 | |
| Potential dilutive effect of ordinary shares issuable under employee share schemes | 109,813 | | 87,743 | | 56,985 | |
| Potential dilutive effect of ordinary shares issuable as consideration for BP’s interest in | | | | | | |
| the TNK-BP joint venture | 58,118 | | 197,802 | | 415,016 | |
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| | 20,195,458 | | 21,411,447 | | 22,292,536 | |
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The number of ordinary shares outstanding at 31 December 2006, excluding treasury shares, was 19,510,496,490. Between the reporting date and the date of completion of these financial statements there has been a net decrease of 128,708,405 in the number of ordinary shares outstanding as a result of share buybacks net of share issues. The number of potential ordinary shares issuable through the exercise of employee share options was 111,029,592 at 31 December 2006. There has been a decrease of 25,627,050 in the number of potential ordinary shares between the reporting date and the completion of the financial statements.
Earnings (loss) per share for the discontinued operations is derived from the net profit (loss) attributable to ordinary shareholders from discontinued operations of $25 million loss (2005 $184 million profit and 2004 $622 million loss), divided by the weighted average number of ordinary shares for both basic and diluted amounts as shown above.
Back to Contents
26 Property, plant and equipment
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | Oil depots, | | | | | |
| | | | | | | | Plant, | | Fixtures, | | | | storage | | | | Of which: | |
| | Land | | | | Oil and | | machinery | | fittings and | | | | tanks and | | | | assets | |
| | and land | | | | gas | | and | | office | | Transport- | | service | | | | under | |
| | improvements | | Buildings | | properties | | equipment | | equipment | | ation | | stations | | Total | | construction | |
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| Cost | | | | | | | | | | | | | | | | | | |
| At 1 January 2006 | 4,576 | | 2,835 | | 113,474 | | 28,780 | | 2,247 | | 13,266 | | 11,235 | | 176,413 | | 16,115 | |
| Exchange adjustments | 255 | | 239 | | 72 | | 1,028 | | 138 | | 27 | | 517 | | 2,276 | | 137 | |
| Acquisitions | – | | – | | – | | 16 | | – | | – | | – | | 16 | | – | |
| Additions | 81 | | 381 | | 11,264 | | 2,146 | | 841 | | 22 | | 918 | | 15,653 | | 11,560 | |
| Transfersa | – | | – | | (628 | ) | – | | (1 | ) | – | | – | | (629 | ) | (9,787 | ) |
| Reclassified as assets held for sale | (15 | ) | (1 | ) | – | | (842 | ) | – | | (1 | ) | (47 | ) | (906 | ) | – | |
| Deletions | (455 | ) | (325 | ) | (5,628 | ) | (486 | ) | (219 | ) | (1,314 | ) | (1,412 | ) | (9,839 | ) | (225 | ) |
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| At 31 December 2006 | 4,442 | | 3,129 | | 118,554 | | 30,642 | | 3,006 | | 12,000 | | 11,211 | | 182,984 | | 17,800 | |
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| Depreciation | | | | | | | | | | | | | | | | | | |
| At 1 January 2006 | 709 | | 1,437 | | 61,253 | | 13,417 | | 1,450 | | 7,104 | | 5,096 | | 90,466 | | | |
| Exchange adjustments | 15 | | 147 | | 54 | | 552 | | 107 | | 12 | | 154 | | 1,041 | | | |
| Charge for the year | 52 | | 149 | | 6,214 | | 1,059 | | 418 | | 301 | | 718 | | 8,911 | | | |
| Impairment losses | 87 | | 5 | | 4 | | 98 | | – | | 1 | | 9 | | 204 | | | |
| Impairment reversals | – | | – | | (340 | ) | – | | – | | – | | – | | (340 | ) | | |
| Transfersb | – | | – | | (887 | ) | – | | (1 | ) | – | | – | | (888 | ) | | |
| Reclassified as assets held for sale | – | | (1 | ) | – | | (325 | ) | – | | (1 | ) | (15 | ) | (342 | ) | | |
| Deletions | (188 | ) | (267 | ) | (5,048 | ) | (173 | ) | (212 | ) | (471 | ) | (708 | ) | (7,067 | ) | | |
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| At 31 December 2006 | 675 | | 1,470 | | 61,250 | | 14,628 | | 1,762 | | 6,946 | | 5,254 | | 91,985 | | | |
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| Net book amount at 31 December 2006 | 3,767 | | 1,659 | | 57,304 | | 16,014 | | 1,244 | | 5,054 | | 5,957 | | 90,999 | | 17,800 | |
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| Cost | | | | | | | | | | | | | | | | | | |
| At 1 January 2005 | 5,471 | | 2,846 | | 107,066 | | 42,302 | | 2,827 | | 13,588 | | 12,421 | | 186,521 | | 15,038 | |
| Exchange adjustments | (387 | ) | (136 | ) | (15 | ) | (2,364 | ) | (180 | ) | (4 | ) | (1,117 | ) | (4,203 | ) | (66 | ) |
| Acquisitions | 19 | | 3 | | – | | – | | 1 | | – | | – | | 23 | | 27 | |
| Additions | 41 | | 191 | | 8,773 | | 2,451 | | 383 | | 133 | | 816 | | 12,788 | | 10,467 | |
| Transfers | – | | – | | 325 | | – | | – | | – | | – | | 325 | | (8,668 | ) |
| Deletions | (568 | ) | (69 | ) | (2,675 | ) | (13,609 | ) | (784 | ) | (451 | ) | (885 | ) | (19,041 | ) | (683 | ) |
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| At 31 December 2005 | 4,576 | | 2,835 | | 113,474 | | 28,780 | | 2,247 | | 13,266 | | 11,235 | | 176,413 | | 16,115 | |
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| Depreciation | | | | | | | | | | | | | | | | | | |
| At 1 January 2005 | 863 | | 1,419 | | 57,111 | | 19,556 | | 1,859 | | 7,141 | | 5,480 | | 93,429 | | | |
| Exchange adjustments | (17 | ) | (60 | ) | (7 | ) | (916 | ) | (67 | ) | (76 | ) | (496 | ) | (1,639 | ) | | |
| Charge for the year | 79 | | 143 | | 5,696 | | 1,691 | | 399 | | 309 | | 704 | | 9,021 | | | |
| Impairment losses | – | | – | | 266 | | 590 | | – | | – | | 42 | | 898 | | | |
| Transfers | – | | – | | 6 | | – | | – | | – | | – | | 6 | | | |
| Deletions | (216 | ) | (65 | ) | (1,819 | ) | (7,504 | ) | (741 | ) | (270 | ) | (634 | ) | (11,249 | ) | | |
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| At 31 December 2005 | 709 | | 1,437 | | 61,253 | | 13,417 | | 1,450 | | 7,104 | | 5,096 | | 90,466 | | | |
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| Net book amount at 31 December 2005 | 3,867 | | 1,398 | | 52,221 | | 15,363 | | 797 | | 6,162 | | 6,139 | | 85,947 | | 16,115 | |
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| Assets held under finance leases at | | | | | | | | | | | | | | | | | | |
| net book amount included above | | | | | | | | | | | | | | | | | | |
| At 31 December 2006 | 5 | | 18 | | 42 | | 341 | | 1 | | 9 | | 29 | | 445 | | | |
| At 31 December 2005 | 8 | | 24 | | 46 | | 315 | | 2 | | 9 | | 35 | | 439 | | | |
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| Decommissioning asset at net book | | | | | | | | | | | | | | | | | | |
| amount included above | | | | | | | | | | | | | | | | | | |
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| | Cost | | Depreciation | | Net | |
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| At 31 December 2006 | 6,391 | | 2,558 | | 3,833 | |
| At 31 December 2005 | 5,398 | | 2,342 | | 3,056 | |
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| a | Includes $1,087 million transferred to equity-accounted investments. |
| b | Includes $890 million transferred to equity-accounted investments. |
Back to Contents
27 Goodwill
| | | | $ million | |
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| | 2006 | | 2005 | |
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| Cost | | | | |
| At 1 January | 10,371 | | 11,182 | |
| Exchange adjustments | 524 | | (488 | ) |
| Acquisitions | 64 | | 86 | |
| Reclassified as assets held for sale | (60 | ) | – | |
| Deletions | (119 | ) | (409 | ) |
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| At 31 December | 10,780 | | 10,371 | |
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| Impairment losses | | | | |
| At 1 January | – | | 325 | |
| Impairment in the year | – | | 59 | |
| Deletions | – | | (384 | ) |
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| At 31 December | – | | – | |
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| Net book amount at 31 December | 10,780 | | 10,371 | |
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28 Intangible assets
| | | | | | | | | | | | $ million | |
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| | | | | | 2006 | | | | | | 2005 | |
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| | Exploration | | Other | | | | Exploration | | Other | | | |
| | expenditure | | intangibles | | Total | | expenditure | | intangibles | | Total | |
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| Cost | | | | | | | | | | | | |
| At 1 January | 4,661 | | 1,740 | | 6,401 | | 4,311 | | 1,377 | | 5,688 | |
| Exchange adjustments | 2 | | 50 | | 52 | | (66 | ) | (44 | ) | (110 | ) |
| Acquisitions | – | | 187 | | 187 | | – | | – | | – | |
| Additions | 1,537 | | 378 | | 1,915 | | 950 | | 531 | | 1,481 | |
| Transfersa | (698 | ) | – | | (698 | ) | (325 | ) | – | | (325 | ) |
| Deletions | (912 | ) | (227 | ) | (1,139 | ) | (209 | ) | (124 | ) | (333 | ) |
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| At 31 December | 4,590 | | 2,128 | | 6,718 | | 4,661 | | 1,740 | | 6,401 | |
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| Amortization | | | | | | | | | | | | |
| At 1 January | 653 | | 976 | | 1,629 | | 550 | | 933 | | 1,483 | |
| Exchange adjustments | – | | 20 | | 20 | | (8 | ) | (32 | ) | (40 | ) |
| Charge for the year | 624 | | 217 | | 841 | | 305 | | 161 | | 466 | |
| Transfers | (2 | ) | – | | (2 | ) | (6 | ) | – | | (6 | ) |
| Impairment losses | 109 | | – | | 109 | | – | | – | | – | |
| Deletions | (904 | ) | (221 | ) | (1,125 | ) | (188 | ) | (86 | ) | (274 | ) |
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| At 31 December | 480 | | 992 | | 1,472 | | 653 | | 976 | | 1,629 | |
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| Net book amount at 31 December | 4,110 | | 1,136 | | 5,246 | | 4,008 | | 764 | | 4,772 | |
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| a | Included in transfers of exploration expenditure is $240 million transferred to equity-accounted investments. |
Back to Contents
29 Investments in jointly controlled entities
The significant jointly controlled entities of the BP group at 31 December 2006 are shown in Note 50. The principal joint venture is the TNK-BP joint venture. Summarized financial information for the group’s share of jointly controlled entities is shown below.
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | 2006 | | | | | | 2005 | | | | | | 2004 | |
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| | TNK-BP | | Other | | Total | | TNK-BP | | Other | | Total | | TNK-BP | | Other | | Total | |
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| Sales and other operating revenues | 17,863 | | 6,119 | | 23,982 | | 15,122 | | 4,255 | | 19,377 | | 7,839 | | 2,225 | | 10,064 | |
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| Profit before interest and taxation | 4,616 | | 1,218 | | 5,834 | | 3,817 | | 779 | | 4,596 | | 2,421 | | 586 | | 3,007 | |
| Finance costs and other finance expense | 192 | | 169 | | 361 | | 128 | | 104 | | 232 | | 101 | | 69 | | 170 | |
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| Profit before taxation | 4,424 | | 1,049 | | 5,473 | | 3,689 | | 675 | | 4,364 | | 2,320 | | 517 | | 2,837 | |
| Taxation | 1,467 | | 260 | | 1,727 | | 976 | | 220 | | 1,196 | | 675 | | 314 | | 989 | |
| Minority interest | 193 | | – | | 193 | | 104 | | – | | 104 | | 43 | | – | | 43 | |
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| Profit for the yeara | 2,764 | | 789 | | 3,553 | | 2,609 | | 455 | | 3,064 | | 1,602 | | 203 | | 1,805 | |
| Innovene operations | – | | – | | – | | – | | 19 | | 19 | | – | | 13 | | 13 | |
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| Continuing operations | 2,764 | | 789 | | 3,553 | | 2,609 | | 474 | | 3,083 | | 1,602 | | 216 | | 1,818 | |
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| Non-current assets | 11,243 | | 7,612 | | 18,855 | | 11,564 | | 6,310 | | 17,874 | | | | | | | |
| Current assets | 5,403 | | 2,184 | | 7,587 | | 4,278 | | 1,682 | | 5,960 | | | | | | | |
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| Total assets | 16,646 | | 9,796 | | 26,442 | | 15,842 | | 7,992 | | 23,834 | | | | | | | |
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| Current liabilities | 3,594 | | 1,272 | | 4,866 | | 3,617 | | 914 | | 4,531 | | | | | | | |
| Non-current liabilities | 4,226 | | 3,370 | | 7,596 | | 3,553 | | 2,550 | | 6,103 | | | | | | | |
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| Total liabilities | 7,820 | | 4,642 | | 12,462 | | 7,170 | | 3,464 | | 10,634 | | | | | | | |
| Minority interest | 473 | | – | | 473 | | 583 | | – | | 583 | | | | | | | |
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| | 8,353 | | 5,154 | | 13,507 | | 8,089 | | 4,528 | | 12,617 | | | | | | | |
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| Group investment in jointly controlled entities | | | | | | | | | | | | | | | | | | |
| Group share of net assets (as above)b | 8,353 | | 5,154 | | 13,507 | | 8,089 | | 4,528 | | 12,617 | | | | | | | |
| Loans made by group companies to jointly | | | | | | | | | | | | | | | | | | |
| controlled entities | – | | 1,567 | | 1,567 | | – | | 939 | | 939 | | | | | | | |
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| | 8,353 | | 6,721 | | 15,074 | | 8,089 | | 5,467 | | 13,556 | | | | | | | |
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| a | BP’s share of the profit of TNK-BP in 2006 includes a net gain of $892 million (2005 $270 million) on the disposal of certain assets. |
| b | Total includes BP’s share of retained earnings of $2,752 million (2005 $2,242 million). |
In 2004, BP agreed with the Alfa Group and Access-Renova (AAR), its partner in the TNK-BP joint venture, to incorporate AAR’s 50% interest in Slavneft into TNK-BP in return for $1,418 million in cash (which was subsequently reduced by receipt of pre-acquisition dividends of $64 million to $1,354 million).
BP Solvay Polyethylene Europe became a subsidiary with effect from 2 November 2004. See Note 4 for further information. In 2005, it was sold as part of the Innovene operations.
During 2004, BP China and Sinopec announced the establishment of the BP-Sinopec (Zhejiang) Petroleum Co. Ltd, a retail joint venture between BP and Sinopec. Based on the existing service station network of Sinopec, the joint venture will build, operate and manage a network of 500 service stations in Hangzhou, Ningbo and Shaoxing. Also during 2004, BP China and PetroChina announced the establishment of BP-PetroChina Petroleum Company Ltd. Located in Guangdong, one of the most developed provinces in China, the joint venture will acquire, build, operate and manage 500 service stations in the province. The initial investment in both joint ventures amounted to $106 million.
Transactions between the significant jointly controlled entities and the group are summarized below. In addition to the amount receivable at 31 December 2005 shown below, a further $771 million was receivable from TNK-BP in respect of dividends: there was no dividend receivable at 31 December 2006.
| Sales to jointly controlled entities | | | | | | | | | | | | | | $ million | |
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| | | | | | | 2006 | | | | 2005 | | | | 2004 | |
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| | | | | | | Amount | | | | Amount | | | | Amount | |
| | | | | | | receivable at | | | | receivable at | | | | receivable at | |
| | | Product | | Sales | | 31 December | | Sales | | 31 December | | Sales | | 31 December | |
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| Atlantic 4 Holdings | | LNG | | 227 | | 35 | | – | | – | | – | | – | |
| Atlantic LNG 2/3 Company of Trinidad and Tobago | | LNG | | 1,123 | | 99 | | 1,157 | | – | | 532 | | – | |
| BP Solvay Polyethylene Europea | | Chemicals feedstocks | | – | | – | | – | | – | | 230 | | – | |
| Pan American Energy | | Crude oil | | 389 | | – | | 75 | | 2 | | 118 | | 4 | |
| Ruhr Oel | | Employee services | | 330 | | 597 | | 169 | | 527 | | 192 | | 780 | |
| TNK-BP | | Employee services | | 189 | | 99 | | 125 | | 14 | | 49 | | – | |
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| a | The 2004 sales to BP Solvay Polyethylene Europe shown above relate to the period to 2 November 2004. |
Back to Contents
29 Investments in jointly controlled entitiescontinued
| Purchases from jointly controlled entities | | | | | | | | | | | | $ million | |
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| | | | | | | 2006 | | | | 2005 | | | | 2004 | |
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| | | | | | | Amount | | | | Amount | | | | Amount | |
| | | | | | | payable at | | | | payable at | | | | payable at | |
| | | Product | | Purchases | | 31 December | | Purchases | | 31 December | | Purchases | | 31 December | |
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| Atlantic LNG 2/3 Company of Trinidad and Tobago | | Plant processing fee/natural gas | | 254 | | – | | 190 | | – | | 120 | | – | |
| Pan American Energy | | Crude oil | | 4 | | 2 | | 661 | | 81 | | 481 | | 43 | |
| Ruhr Oel | | Refinery operating costs | | 758 | | 32 | | 384 | | 134 | | 477 | | 249 | |
| TNK-BP | | Crude oil and oil products | | 2,662 | | 85 | | 908 | | 17 | | 1,809 | | 80 | |
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30 Investments in associates
The significant associates of the group are shown in Note 50. Summarized financial information for the group’s share of associates is set out below.
| | | | | | | $ million | |
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| | | 2006 | | 2005 | | 2004 | |
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|
|
| Sales and other operating revenues | | 8,792 | | 6,879 | | 5,509 | |
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|
|
|
|
|
|
|
| Profit before interest and taxation | | 669 | | 665 | | 632 | |
| Finance costs and other finance expense | | 63 | | 57 | | 48 | |
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|
|
|
|
|
|
| Profit before taxation | | 606 | | 608 | | 584 | |
| Taxation | | 164 | | 143 | | 121 | |
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|
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|
|
| Profit for the year | | 442 | | 465 | | 463 | |
| Innovene operations | | – | | (5 | ) | (1 | ) |
|
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|
|
| Continuing operations | | 442 | | 460 | | 462 | |
|
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|
|
|
|
|
|
| Non-current assets | | 6,573 | | 5,514 | | | |
| Current assets | | 2,294 | | 2,248 | | | |
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| | |
| Total assets | | 8,867 | | 7,762 | | | |
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| | |
| Current liabilities | | 2,029 | | 1,755 | | | |
| Non-current liabilities | | 2,600 | | 2,037 | | | |
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| | |
| Total liabilities | | 4,629 | | 3,792 | | | |
|
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| | |
| Net assets | | 4,238 | | 3,970 | | | |
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| | |
| Group investment in associates | | | | | | | |
| Group share of net assets (as above)a | | 4,238 | | 3,970 | | | |
| Loans made by group companies to associates | | 1,737 | | 2,247 | | | |
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| | |
| | | 5,975 | | 6,217 | | | |
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| | |
| a | Includes BP’s share of retained earnings of $480 million (2005 $696 million). |
BP Solvay Polyethylene North America became a subsidiary with effect from 2 November 2004. See Note 4 for further information. In 2005, it was sold as part of the Innovene operations.
Transactions between the significant associates and the group are summarized below.
| Sales to associates | | | | | | | | | | | | | $ million | |
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| | | | | | 2006 | | | | 2005 | | | | 2004 | |
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| | | | | | Amount | | | | Amount | | | | Amount | |
| | | | | | receivable at | | | | receivable at | | | | receivable at | |
| | Product | | Sales | | 31 December | | Sales | | 31 December | | Sales | | 31 December | |
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| Atlantic LNG Company of Trinidad and Tobago | LNG | | 635 | | 62 | | 579 | | – | | 414 | | – | |
| The Baku-Tbilisi-Ceyhan Pipeline Co | Crude oil/employee | | | | | | | | | | | | | |
| | services | | 112 | | 4 | | 99 | | 3 | | 46 | | 3 | |
| BP Solvay Polyethylene North Americaa | Chemicals feedstocks | | – | | – | | – | | – | | 217 | | – | |
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| | | | | | | | | | | | | | | |
| Purchases from associates | | | | | | | | | | | | | $ million | |
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| | | | | | 2006 | | | | 2005 | | | | 2004 | |
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| | | | | | Amount | | | | Amount | | | | Amount | |
| | | | | | payable at | | | | payable at | | | | payable at | |
| | Product | | Purchases | | 31 December | | Purchases | | 31 December | | Purchases | | 31 December | |
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| Abu Dhabi Marine Areas | Crude oil | | 866 | | 91 | | 1,355 | | 164 | | 866 | | 91 | |
| Abu Dhabi Petroleum Co. | Crude oil | | 1,547 | | 145 | | 2,260 | | 214 | | 1,547 | | 145 | |
| The Baku-Tbilisi-Ceyhan Pipeline Co | Crude oil | | 155 | | – | | – | | – | | – | | – | |
| BP Solvay Polyethylene North Americaa | Chemicals feedstocks | | – | | – | | – | | – | | 9 | | – | |
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| a | The 2004 BP Solvay Polyethylene North America sales and purchases shown above relate to the period to 2 November 2004. |
Back to Contents
31 Other investments
| | | | | $ million | |
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| | | 2006 | | 2005 | |
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| Listed | | 1,516 | | 830 | |
| Unlisted | | 181 | | 137 | |
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| | | 1,697 | | 967 | |
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|
Other investments comprise equity investments that have no fixed maturity date or coupon rate. These investments are classified as available-for-sale financial assets and as such are recorded at fair value with the gain or loss arising as a result of changes in fair value recorded directly in equity.
The fair value of listed investments has been determined by reference to quoted market bid prices. Unlisted investments are stated at cost less accumulated impairment losses.
The table below shows other investments stated at cost.
| | | | | $ million | |
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| | | 2006 | | 2005 | |
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| At cost | | | | | |
| Listed | | 1,056 | | 250 | |
| Unlisted | | 219 | | 173 | |
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| | | 1,275 | | 423 | |
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During 2006, the group sold its interests in Zhenhai Refining and Chemicals Company, Eiffage, the French-based construction company, and Enagas, the Spanish gas transport grid operator, for aggregate proceeds of $0.8 billion, recognizing gains of $0.5 billion. Also in 2006, the group acquired a stake in Rosneft for $1 billion. In 2004, the group disposed of its interests in PetroChina and Sinopec for aggregate proceeds of $2.4 billion and recognized gains of $1.3 billion.
32 Inventories
| | | | | $ million | |
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| | | 2006 | | 2005 | |
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| Crude oil | | 5,357 | | 5,457 | |
| Natural gas | | 127 | | 164 | |
| Refined petroleum and petrochemical products | | 10,817 | | 10,700 | |
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| | | 16,301 | | 16,321 | |
| Supplies | | 1,222 | | 919 | |
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| | | 17,523 | | 17,240 | |
| Trading inventories | | 1,392 | | 2,520 | |
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| | | 18,915 | | 19,760 | |
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| Cost of inventories expensed in the income statement | | 187,183 | | 163,026 | |
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Back to Contents
33 Trade and other receivables
| | | | | | | | | $ million | |
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| | | | | 2006 | | | | 2005 | |
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| | | Current | | Non-current | | Current | | Non-current | |
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| Trade | | 32,656 | | – | | 33,565 | | – | |
| Jointly controlled entities | | 635 | | – | | 1,345 | | – | |
| Associates | | 267 | | – | | 186 | | – | |
| Other | | 5,134 | | 862 | | 5,806 | | 770 | |
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|
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|
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| | | 38,692 | | 862 | | 40,902 | | 770 | |
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| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | 2006 | | | | | | | | | | 2005 | |
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| | | | | | | Currency of denomination | | | | | | | | Currency of denomination | |
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| | | | | | | | Other | | | | | | | | | | Other | | | |
| | US dollar | | Sterling | | Euro | | currencies | | Total | | US dollar | | Sterling | | Euro | | currencies | | Total | |
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| Functional currency | | | | | | | | | | | | | | | | | | | | |
| US dollar | – | | 1,217 | | 123 | | 5,286 | | 6,626 | | – | | 1,111 | | 354 | | 6,045 | | 7,510 | |
| Sterling | 376 | | – | | 1,652 | | 39 | | 2,067 | | 404 | | – | | 453 | | 15 | | 872 | |
| Euro | 692 | | 7 | | – | | 1 | | 700 | | 1,496 | | 1 | | – | | 948 | | 2,445 | |
| Other currencies | 248 | | 1 | | 1 | | – | | 250 | | 458 | | 1 | | 1 | | – | | 460 | |
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| | 1,316 | | 1,225 | | 1,776 | | 5,326 | | 9,643 | | 2,358 | | 1,113 | | 808 | | 7,008 | | 11,287 | |
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Trade and other receivables of the group at 31 December have the maturities shown below.
| | | | | $ million | |
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|
| | | 2006 | | 2005 | |
|
|
|
|
|
|
| Within one year | | 38,692 | | 40,902 | |
| 1 to 2 years | | 187 | | 129 | |
| 2 to 3 years | | 86 | | 82 | |
| 3 to 4 years | | 82 | | 56 | |
| 4 to 5 years | | 76 | | 51 | |
| Over 5 years | | 431 | | 452 | |
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|
|
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|
|
| | | 39,554 | | 41,672 | |
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|
|
The movement in the valuation allowance for trade receivables is set out below.
| | | | | $ million | |
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|
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|
|
| | | 2006 | | 2005 | |
|
|
|
|
|
|
| At 1 January | | 374 | | 526 | |
| Exchange adjustments | | 32 | | (30 | ) |
| Charge for the year | | 158 | | 67 | |
| Utilization | | (143 | ) | (189 | ) |
|
|
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|
|
| At 31 December | | 421 | | 374 | |
|
|
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|
|
The carrying amounts of Trade and other receivables approximate their fair value. Trade and other receivables are predominantly non-interest bearing.
34 Cash and cash equivalents
| | | | | $ million | |
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|
| | | 2006 | | 2005 | |
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|
|
| Cash at bank and in hand | | 2,052 | | 1,594 | |
| Cash equivalents | | | | | |
| Listed | | 29 | | 73 | |
| Unlisted | | 509 | | 1,293 | |
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|
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|
|
|
| Carrying amount at 31 December | | 2,590 | | 2,960 | |
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|
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|
|
|
Cash equivalents are classified as available-for-sale financial assets and as such are recorded at fair value. Cash and cash equivalents at 31 December 2006 includes $773 million which is restricted. This relates principally to amounts on deposit to cover trading positions on trading exchanges.
Back to Contents
35 Trade and other payables
| $ million | |
|
| | 2006 | 2005 | |
|
| | Current | Non-current | Current | Non-current | |
|
| Trade | 28,319 | – | 28,614 | – | |
| Jointly controlled entities | 87 | – | 251 | – | |
| Associates | 305 | – | 627 | – | |
| Production and similar taxes | 852 | 899 | 763 | 1,281 | |
| Social security | 59 | – | 78 | – | |
| Other | 12,614 | 531 | 11,803 | 654 | |
|
| | 42,236 | 1,430 | 42,136 | 1,935 | |
|
| $ million | |
|
| | 2006 | 2005 | |
|
| | Currency of denomination | Currency of denomination | |
| | | | | Other | | | | | Other | | |
| | US dollar | Sterling | Euro | currencies | Total | US dollar | Sterling | Euro | currencies | Total | |
|
| Functional currency | | | | | | | | | | | |
| US dollar | – | 1,476 | 165 | 5,818 | 7,459 | – | 1,802 | 157 | 6,640 | 8,599 | |
| Sterling | 396 | – | 507 | – | 903 | 133 | – | 306 | – | 439 | |
| Euro | 185 | 2 | – | 1 | 188 | 611 | 4 | – | 17 | 632 | |
| Other currencies | 322 | 4 | 8 | – | 334 | 339 | 12 | 38 | – | 389 | |
|
| | 903 | 1,482 | 680 | 5,819 | 8,884 | 1,083 | 1,818 | 501 | 6,657 | 10,059 | |
|
Trade and other payables of the group at 31 December 2006 have the maturities shown below.
| | | $ million | |
|
| | 2006 | 2005 | |
|
| Within one year | 42,236 | 42,136 | |
| 1 to 2 years | 269 | 276 | |
| 2 to 3 years | 215 | 211 | |
| 3 to 4 years | 153 | 182 | |
| 4 to 5 years | 184 | 179 | |
| Over 5 years | 609 | 1,087 | |
|
| | 43,666 | 44,071 | |
|
The carrying amounts of Trade and other payables approximate their fair value. Included within Other payables for 2005 was the deferred consideration for the acquisition of our interest in TNK-BP, which was discounted on initial recognition. The remaining Trade and other payables are predominantly interest free.
Back to Contents
36 Derivative financial instruments
An outline of the group’s financial risks and the policies and objectives pursued in relation to those risks is set out in the quantitative and qualitative disclosures about market risk section on pages 54-57.
This note contains the disclosures required by IAS 32 for derivative financial instruments. IAS 39 prescribes strict criteria for hedge accounting, whether as a cash flow or fair value hedge, and requires that any derivative that does not meet these criteria should be classified as held for trading and fair valued. BP adopted IAS 32 and IAS 39 with effect from 1 January 2005 without restating prior periods’ financial information. Consequently, the group’s accounting policy under UK GAAP has been used for 2004. The policy under UK GAAP and the disclosures required by UK GAAP for derivative financial instruments are shown in Note 37.
In the normal course of business the group is a party to derivative financial instruments (derivatives) to manage its normal business exposures in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt consistent with risk management policies and objectives. Additionally, the group has a well-established trading activity that is undertaken in conjunction with each of these activities using a similar range of contracts.
The fair value of derivative financial instruments at 31 December are set out below.
| | | | | | | | | | | $ million | |
|
| | | | | | 2006 | | | | | 2005 | |
|
| | Fair | Contractual | Fair | | Contractual | Fair | Contractual | Fair | | Contractual | |
| | value | or notional | value or | | notional | value | or notional | value | | or notional | |
| | asset | amounts | liability | | amounts | asset | amounts | liability | | amounts | |
|
| Derivatives held for trading | | | | | | | | | | | |
| Currency derivatives | 137 | 6,820 | (32 | ) | 3,923 | 41 | 634 | (18 | ) | 1,687 | |
| Oil derivatives | 2,664 | 57,600 | (2,368 | ) | 59,524 | 2,765 | 56,394 | (2,826 | ) | 52,524 | |
| Natural gas derivatives | 6,558 | 139,961 | (5,703 | ) | 107,145 | 6,836 | 148,794 | (6,307 | ) | 128,330 | |
| Power derivatives | 3,232 | 22,250 | (3,190 | ) | 25,859 | 3,341 | 25,793 | (3,158 | ) | 26,618 | |
| Other derivatives | 113 | 499 | – | | – | – | – | – | | – | |
|
| | 12,704 | 227,130 | (11,293 | ) | 196,451 | 12,983 | 231,615 | (12,309 | ) | 209,159 | |
|
| Embedded derivatives | | | | | | | | | | | |
| Natural gas and LNG contracts | 107 | 219 | (2,171 | ) | 11,810 | 587 | 4,620 | (3,098 | ) | 8,563 | |
| Interest rate contracts | – | – | (26 | ) | 150 | – | – | (30 | ) | 150 | |
|
| | 107 | 219 | (2,197 | ) | 11,960 | 587 | 4,620 | (3,128 | ) | 8,713 | |
|
| Cash flow hedges | | | | | | | | | | | |
| Currency forwards, futures and swaps | 205 | 2,223 | (33 | ) | 1,274 | 34 | 666 | (94 | ) | 3,100 | |
| Currency options | 14 | 2,677 | – | | – | – | 693 | (35 | ) | 1,470 | |
| Commodity futures | – | – | – | | – | 57 | 274 | – | | – | |
|
| | 219 | 4,900 | (33 | ) | 1,274 | 91 | 1,633 | (129 | ) | 4,570 | |
|
| Fair value hedges | | | | | | | | | | | |
| Currency forwards, futures and swaps | 228 | 3,865 | (13 | ) | 598 | 222 | 2,566 | (124 | ) | 1,967 | |
| Interest rate swaps | 33 | 1,688 | (91 | ) | 4,397 | 19 | 324 | (217 | ) | 7,521 | |
|
| | 261 | 5,553 | (104 | ) | 4,995 | 241 | 2,890 | (341 | ) | 9,488 | |
|
| Hedges of net investments in foreign entities | 107 | 394 | – | | – | 63 | 346 | – | | – | |
|
| | 13,398 | 238,196 | (13,627 | ) | 214,680 | 13,965 | 241,104 | (15,907 | ) | 231,930 | |
|
| Of which – current | 10,373 | | (9,424 | ) | | 10,056 | | (10,036 | ) | | |
| Of which – non-current | 3,025 | | (4,203 | ) | | 3,909 | | (5,871 | ) | | |
|
The fair values of embedded derivatives are included within non-current and current derivative financial instruments on the group balance sheet as this is believed to be the most appropriate presentation. Previously, these balances were reported within non-current and current prepayments and accrued income and accruals and deferred income. The comparative figures have been restated to conform with the 2006 presentation.
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. This activity is undertaken in conjunction with risk management activities. Derivatives held for trading purposes are recognized at fair value and changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk techniques described in the section on market risk exposure.
Back to Contents
36 Derivative financial instruments continued
The following tables show the fair value of derivatives and other financial instruments held for trading purposes. The fair values at the year end are not materially unrepresentative of the position throughout the year.
Changes during the year in the net fair value of derivatives held for trading purposes were as follows.
| | | | | | | | | | $ million | |
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|
|
|
| | | | Oil | | Natural gas | | Power | | | |
| | Currency | | price | | price | | price | | Other | |
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|
| Fair value of contracts at 1 January 2006 | 23 | | (61 | ) | 529 | | 183 | | – | |
| Contracts realized or settled in the year | (16 | ) | 85 | | (327 | ) | (37 | ) | (106 | ) |
| Fair value of options at inception | – | | 36 | | 247 | | (70 | ) | 45 | |
| Fair value of other new contracts entered into during the year | – | | – | | 2 | | 1 | | – | |
| Change in fair value due to changes in valuation techniques or key assumptions | – | | 1 | | – | | – | | – | |
| Other changes in fair values relating to price | 98 | | 231 | | 421 | | (22 | ) | 174 | |
| Exchange adjustments | – | | 4 | | (17 | ) | (13 | ) | – | |
|
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|
|
|
| Fair value of contracts at 31 December 2006 | 105 | | 296 | | 855 | | 42 | | 113 | |
|
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|
| | | | | | | | | | $ million | |
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|
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|
| | | | Oil | | Natural gas | | Power | | | |
| | Currency | | price | | price | | price | | Other | |
|
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|
|
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|
|
|
| Fair value of contracts at 1 January 2005 | (54 | ) | (171 | ) | 558 | | 177 | | – | |
| Contracts realized or settled in the year | 23 | | 175 | | (735 | ) | 76 | | – | |
| Fair value of options at inception | – | | (73 | ) | (65 | ) | (9 | ) | – | |
| Fair value of other new contracts entered into during the year | – | | – | | 24 | | 10 | | – | |
| Other changes in fair values relating to price | 54 | | 8 | | 747 | | (71 | ) | – | |
|
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|
| Fair value of contracts at 31 December 2005 | 23 | | (61 | ) | 529 | | 183 | | – | |
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|
If at inception of a contract the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and commonly known as ‘day one profit’. When all of the remaining contracts can be valued using observable market data this gain or loss is recognized in income. Changes in valuation from this initial valuation are recognized immediately through income.
The following table shows the change in the associated fair value of assets and liabilities.
| | | | | | | | $ million | |
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|
|
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|
|
|
|
|
| | | | 2006 | | | | 2005 | |
|
|
|
|
|
|
|
|
|
| | Natural | | | | Natural | | | |
| | gas price | | Power price | | gas price | | Power price | |
|
|
|
|
|
|
|
|
|
| Fair value of contracts not recognized through the income statement at 1 January | (39 | ) | (10 | ) | (15 | ) | – | |
| Fair value of new contracts at inception not recognized in the income statement | (2 | ) | (1 | ) | (24 | ) | (10 | ) |
| Fair value recycled into the income statement | 5 | | 11 | | – | | – | |
|
|
|
|
|
|
|
|
|
| Fair value of contracts not recognized through profit at 31 December | (36 | ) | – | | (39 | ) | (10 | ) |
|
|
|
|
|
|
|
|
|
Derivative assets held for trading have the following fair values, contractual or notional values and maturities.
| | | | | | | | $ million | |
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|
|
|
|
|
|
|
| | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
| | Less than | | | | | Over | | |
| | 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | |
|
|
|
|
|
|
|
|
|
| Currency derivatives | | | | | | | | |
| Fair value | 117 | – | 12 | 3 | 2 | 3 | 137 | |
| Notional value | 6,338 | 75 | 241 | 89 | 54 | 23 | 6,820 | |
| Oil price derivatives | | | | | | | | |
| Fair value | 2,520 | 116 | 20 | 7 | 1 | – | 2,664 | |
| Notional value | 52,591 | 4,736 | 210 | 62 | 1 | – | 57,600 | |
| Natural gas price derivatives | | | | | | | | |
| Fair value | 4,532 | 919 | 374 | 166 | 114 | 453 | 6,558 | |
| Notional value | 81,102 | 33,499 | 9,837 | 5,186 | 3,396 | 6,941 | 139,961 | |
| Power price derivatives | | | | | | | | |
| Fair value | 2,845 | 274 | 86 | 27 | – | – | 3,232 | |
| Notional value | 16,063 | 4,999 | 1,171 | 17 | – | – | 22,250 | |
| Other derivatives | | | | | | | | |
| Fair value | 64 | 26 | 23 | – | – | – | 113 | |
| Notional value | 213 | 149 | 137 | – | – | – | 499 | |
| Total derivative assets held for trading | | | | | | | | |
| Fair value | 10,078 | 1,335 | 515 | 203 | 117 | 456 | 12,704 | |
| Notional value | 156,307 | 43,458 | 11,596 | 5,354 | 3,451 | 6,964 | 227,130 | |
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Back to Contents
36 Derivative financial instruments continued
| | | | | | | | $ million | |
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| | Less than | | | | | Over | | |
| | 1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | |
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| Currency derivatives | | | | | | | | |
| Fair value | 28 | 6 | 1 | 1 | 1 | 4 | 41 | |
| Notional value | 358 | 73 | 51 | 28 | 32 | 92 | 634 | |
| Oil price derivatives | | | | | | | | |
| Fair value | 2,476 | 225 | 37 | 19 | 8 | – | 2,765 | |
| Notional value | 52,260 | 3,378 | 676 | 45 | 35 | – | 56,394 | |
| Natural gas price derivatives | | | | | | | | |
| Fair value | 4,509 | 1,194 | 528 | 292 | 125 | 188 | 6,836 | |
| Notional value | 113,897 | 17,562 | 8,560 | 4,021 | 2,068 | 2,686 | 148,794 | |
| Power price derivatives | | | | | | | | |
| Fair value | 2,474 | 594 | 119 | 143 | 11 | – | 3,341 | |
| Notional value | 19,156 | 5,049 | 857 | 535 | 196 | – | 25,793 | |
| Total derivative assets held for trading | | | | | | | | |
| Fair value | 9,487 | 2,019 | 685 | 455 | 145 | 192 | 12,983 | |
| Notional value | 185,671 | 26,062 | 10,144 | 4,629 | 2,331 | 2,778 | 231,615 | |
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Derivative liabilities held for trading have the following fair values, contractual or notional values and maturities.
| | | | | | | | | | | | | | $ million | |
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| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
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| Currency derivatives | | | | | | | | | | | | | | |
| Fair value | (8 | ) | (7 | ) | (12 | ) | (2 | ) | (2 | ) | (1 | ) | (32 | ) |
| Notional value | 3,183 | | 204 | | 214 | | 92 | | 56 | | 174 | | 3,923 | |
| Oil price derivatives | | | | | | | | | | | | | | |
| Fair value | (2,230 | ) | (89 | ) | (29 | ) | (19 | ) | (1 | ) | – | | (2,368 | ) |
| Notional value | 55,488 | | 3,541 | | 363 | | 111 | | 21 | | – | | 59,524 | |
| Natural gas price derivatives | | | | | | | | | | | | | | |
| Fair value | (3,931 | ) | (875 | ) | (273 | ) | (109 | ) | (86 | ) | (429 | ) | (5,703 | ) |
| Notional value | 63,593 | | 25,962 | | 7,710 | | 3,059 | | 1,591 | | 5,230 | | 107,145 | |
| Power price derivatives | | | | | | | | | | | | | | |
| Fair value | (2,777 | ) | (289 | ) | (98 | ) | (26 | ) | – | | – | | (3,190 | ) |
| Notional value | 20,086 | | 4,457 | | 1,299 | | 17 | | – | | – | | 25,859 | |
| Total derivative liabilities held for trading | | | | | | | | | | | | | | |
| Fair value | (8,946 | ) | (1,260 | ) | (412 | ) | (156 | ) | (89 | ) | (430 | ) | (11,293 | ) |
| Notional value | 142,350 | | 34,164 | | 9,586 | | 3,279 | | 1,668 | | 5,404 | | 196,451 | |
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| | | | | | | | | | | | | | $ million | |
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| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
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| Currency derivatives | | | | | | | | | | | | | | |
| Fair value | (12 | ) | (4 | ) | (1 | ) | (1 | ) | – | | – | | (18 | ) |
| Notional value | 1,013 | | 177 | | 119 | | 170 | | 67 | | 141 | | 1,687 | |
| Oil price derivatives | | | | | | | | | | | | | | |
| Fair value | (2,486 | ) | (275 | ) | (26 | ) | (20 | ) | (19 | ) | – | | (2,826 | ) |
| Notional value | 49,732 | | 2,276 | | 446 | | 35 | | 35 | | – | | 52,524 | |
| Natural gas price derivatives | | | | | | | | | | | | | | |
| Fair value | (3,967 | ) | (1,319 | ) | (591 | ) | (187 | ) | (89 | ) | (154 | ) | (6,307 | ) |
| Notional value | 90,916 | | 25,269 | | 6,457 | | 2,903 | | 1,577 | | 1,208 | | 128,330 | |
| Power price derivatives | | | | | | | | | | | | | | |
| Fair value | (2,459 | ) | (557 | ) | (59 | ) | (70 | ) | (13 | ) | – | | (3,158 | ) |
| Notional value | 20,030 | | 4,990 | | 778 | | 625 | | 195 | | – | | 26,618 | |
| Total derivative liabilities held for trading | | | | | | | | | | | | | | |
| Fair value | (8,924 | ) | (2,155 | ) | (677 | ) | (278 | ) | (121 | ) | (154 | ) | (12,309 | ) |
| Notional value | 161,691 | | 32,712 | | 7,800 | | 3,733 | | 1,874 | | 1,349 | | 209,159 | |
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Back to Contents
36 Derivative financial instruments continued
The following tables show the net fair value of derivatives held for trading at 31 December analysed by maturity period and by methodology of fair value estimation.
| | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | 2006 | |
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| | Less than | 1-2 | | 2-3 | | 3-4 | | 4-5 | | Over | | | |
| | 1 year | years | | years | | years | | years | | 5 years | | Total | |
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| Prices actively quoted | 191 | 62 | | 60 | | 33 | | – | | 2 | | 348 | |
| Prices sourced from observable data or market corroboration | 911 | 29 | | 54 | | 19 | | 36 | | 4 | | 1,053 | |
| Prices based on models and other valuation methods | 30 | (14 | ) | (12 | ) | (6 | ) | (8 | ) | 20 | | 10 | |
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| | 1,132 | 77 | | 102 | | 46 | | 28 | | 26 | | 1,411 | |
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| | | | | | | | | | | | | $ million | |
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| | Less than | 1-2 | | 2-3 | | 3-4 | | 4-5 | | Over | | | |
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| Prices actively quoted | (100 | (86 | ) | 46 | | 42 | | 33 | | (8 | ) | (73 | ) |
| Prices sourced from observable data or market corroboration | 660 | (48 | ) | (41 | ) | 60 | | (11 | ) | – | | 620 | |
| Prices based on models and other valuation methods | 3 | (2 | ) | 3 | | 75 | | 2 | | 46 | | 127 | |
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| | 563 | (136 | ) | 8 | | 177 | | 24 | | 38 | | 674 | |
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Prices actively quoted refers to the fair value of contracts valued solely using quoted prices in an active market. Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data for example, swaps and physical forward contracts. Prices based on models and other valuation methods refers to the fair value of a contract valued in part using internal models due to the absence of quoted prices, including over-the-counter options. The net change in fair value of contracts based on models and other valuation methods during the year was a loss of $117 million (2005 $130 million gain).
Credit risk
Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. The primary activities of the group are oil and natural gas exploration and production, gas and power marketing and trading, oil refining and marketing and the manufacture and marketing of petrochemicals. The group’s principal customers, suppliers and financial institutions with which it conducts business are located throughout the world.
The group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The group limits credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. Creditworthiness is assessed using Moody’s Investors Service, Standard & Poor’s and qualitative and quantitative data. The group attempts to mitigate credit risk by entering into contracts that permit netting and allow for termination of the contract upon the occurrence of certain events of default. Depending upon the creditworthiness of the counterparty, the group may require collateral in the form of cash deposits or letters of credit and parent company guarantees.
The maximum exposure of the group to credit risk is represented by the balance sheet carrying amount for all financial instruments within the scope of IAS 32, principally derivative financial instruments, trade and other receivables and financial guarantees. Financial guarantees in respect of equity-accounted entities were $1,123 million and financial guarantees in respect of third parties were $789 million at 31 December 2006. The maximum exposure to credit risk does not take account of collateral of $689 million.
Trade and other derivative assets and liabilities are presented on a net basis where netting arrangements are in place with counterparties are unconditional and where there is an intent to settle amounts due on a net basis.
Market risk
The group measures its market risk exposure, i.e. potential gain or loss in fair values, on its held-for-trading activity using value-at-risk techniques. These techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of the end-of-day exposures and the history of one-day price movements, together with the correlation of these price movements. The group calculates value at risk for the bulk of instruments and exposures in the held-for-trading category, other than the UK North Sea natural gas embedded derivatives, for which a sensitivity analysis is calculated.
The potential movement in fair values is expressed to 1.65 standard deviations which is equivalent to a 95% confidence level. This means that, in broad terms, one would expect to see an increase or a decrease in fair values greater than the value at risk on one occasion per month if the portfolio were left unchanged.
The value-at-risk model takes account of derivative financial instrument types such as interest rate forward and futures contracts, swap agreements, options and swaptions; foreign exchange forward and futures contracts, swap agreements and options, and oil, natural gas and power price futures, swap agreements and options. Additionally, where physical commodities are held as part of a trading position, they are also included in these calculations. For options, a linear approximation is included in the value-at-risk models, when full revaluation is not possible.
The following table shows values at risk for the held-for-trading activities described above.
| Value at risk on 1.65 standard deviations | | | | | | | | $ million | |
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| | High | Low | Average | Year end | High | Low | Average | Year end | |
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| Interest rate trading | 1 | – | 1 | – | 1 | – | – | – | |
| Currency trading | 5 | – | 2 | – | 5 | 1 | 2 | 1 | |
| Oil price trading | 56 | 16 | 29 | 22 | 80 | 17 | 33 | 31 | |
| Natural gas price trading | 29 | 10 | 19 | 15 | 39 | 6 | 15 | 17 | |
| Power price trading | 11 | 2 | 6 | 3 | 16 | 2 | 7 | 9 | |
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Back to Contents
36 Derivative financial instruments continued
Gains and losses relating to derivative contracts are included within sales and other operating revenues in the income statement. The contract types treated in this way include futures, options, swaps and certain forward sales and purchase contracts where delivery is routinely obviated by the purchase or sale of offsetting contracts. Also included within sales and other operating revenues are gains and losses on inventory held for trading purposes and the change in fair value of derivative contracts which have been determined to be not for trading purposes but are required to be fair valued. The total amount relating to these items was a gain of $2,842 million (2005 $838 million gain and 2004 $1,216 million gain).
Derivative assets held for trading denominated in currencies other than the functional currency of individual operating units are summarized below.
| | | | | | | | | | | | | | | | | | | | $ million | |
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| | Currency of denomination | | Currency of denomination | |
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| | | | | | | | Other | | | | | | | | | | Other | | | |
| | US dollar | | Sterling | | Euro | | currencies | | Total | | US dollar | | Sterling | | Euro | | currencies | | Total | |
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| Functional currency | | | | | | | | | | | | | | | | | | | | |
| US dollar | – | | 55 | | – | | 244 | | 299 | | – | | 137 | | – | | 4 | | 141 | |
| Sterling | 198 | | – | | 2,227 | | 1 | | 2,426 | | – | | – | | 1,504 | | – | | 1,504 | |
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| | 198 | | 55 | | 2,227 | | 245 | | 2,725 | | – | | 137 | | 1,504 | | 4 | | 1,645 | |
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Derivative liabilities held for trading denominated in currencies other than the functional currency of individual operating units are summarized below.
| | | | | | | | | | | | | | | | | | | | $ million | |
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| | Currency of denomination | | Currency of denomination | |
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| | | | | | | | Other | | | | | | | | | | Other | | | |
| | US dollar | | Sterling | | Euro | | currencies | | Total | | US dollar | | Sterling | | Euro | | currencies | | Total | |
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| Functional currency | | | | | | | | | | | | | | | | | | | | |
| US dollar | – | | (59 | ) | – | | (276 | ) | (335 | ) | – | | (110 | ) | – | | – | | (110 | ) |
| Sterling | (18 | ) | – | | (2,383 | ) | – | | (2,401 | ) | – | | – | | (1,523 | ) | – | | (1,523 | ) |
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| | (18 | ) | (59 | ) | (2,383 | ) | (276 | ) | (2,736 | ) | – | | (110 | ) | (1,523 | ) | – | | (1,633 | ) |
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Embedded derivatives
Prior to the development of an active gas trading market, UK gas contracts were priced using a basket of available price indices, primarily relating to oil products. After the development of an active UK gas market, certain contracts were entered into or renegotiated using pricing formulae not directly related to gas prices, for example, oil product and power prices. In these circumstances, pricing formulae have been determined to be derivatives, embedded within the overall contractual arrangements that are not clearly and closely related to the underlying commodity. The resulting fair value relating to these contracts is recognized on the balance sheet with gains or losses recognized in the income statement.
These contracts are valued using price curves for each of the different products that are built up from active market pricing data and extrapolated to 2018 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.
The following table shows the changes during the year in the net fair value of embedded derivatives.
| | | | | | | | $ million | |
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| | | | 2006 | | | | 2005 | |
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| | Natural gas | | | | Natural gas | | | |
| | and LNG | | Interest | | and LNG | | Interest | |
| | price | | rate | | price | | rate | |
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| Fair value of contracts at 1 January | (2,511 | ) | (30 | ) | (659 | ) | (17 | ) |
| Contracts realized or settled in the year | 762 | | – | | 138 | | – | |
| Other changes in fair values relating to price | 21 | | 4 | | (2,287 | ) | (13 | ) |
| Exchange adjustments | (336 | ) | – | | 297 | | – | |
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| Fair value of contracts at 31 December | (2,064 | ) | (26 | ) | (2,511 | ) | (30 | ) |
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Embedded derivative assets have the following fair values, contractual or notional values and maturities.
| | | | | | | | | | | | | | $ million | |
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| | Less than | | | | | | | | | | Over | | | |
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| Natural gas and LNG embedded derivatives | | | | | | | | | | | | | | |
| Fair value | 49 | | 58 | | – | | – | | – | | – | | 107 | |
| Notional value | 119 | | 100 | | – | | – | | – | | – | | 219 | |
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Back to Contents
36 Derivative financial instruments continued
| | | | | | | | | | | | | | $ million | |
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| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
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| Natural gas and LNG embedded derivatives | | | | | | | | | | | | | | |
| Fair value | 330 | | 176 | | 76 | | 5 | | – | | – | | 587 | |
| Notional value | 425 | | 484 | | 465 | | 450 | | 429 | | 2,367 | | 4,620 | |
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Embedded derivative liabilities have the following fair values, contractual or notional values and maturities.
| | | | | | | | | | | | | | $ million | |
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| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
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| Natural gas and LNG embedded derivatives | | | | | | | | | | | | | | |
| Fair value | (444 | ) | (433 | ) | (320 | ) | (218 | ) | (186 | ) | (570 | ) | (2,171 | ) |
| Notional value | 1,352 | | 1,229 | | 1,279 | | 1,278 | | 1,249 | | 5,423 | | 11,810 | |
| Interest rate embedded derivatives | | | | | | | | | | | | | | |
| Fair value | – | | (26 | ) | – | | – | | – | | – | | (26 | ) |
| Notional value | – | | 150 | | – | | – | | – | | – | | 150 | |
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| | | | | | | | | | | | | | $ million | |
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| | Less than | | | | | | | | | | Over | | | |
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| Natural gas and LNG embedded derivatives | | | | | | | | | | | | | | |
| Fair value | (953 | ) | (703 | ) | (472 | ) | (237 | ) | (180 | ) | (553 | ) | (3,098 | ) |
| Notional value | 740 | | 870 | | 1,097 | | 832 | | 767 | | 4,257 | | 8,563 | |
| Interest rate embedded derivatives | | | | | | | | | | | | | | |
| Fair value | – | | – | | (30 | ) | – | | – | | – | | (30 | ) |
| Notional value | – | | – | | 150 | | – | | – | | – | | 150 | |
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The following tables show the net fair value of embedded derivatives at 31 December analysed by maturity period and by methodology of fair value estimation.
| | | | | | | | | | | | | | $ million | |
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| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
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| Prices actively quoted | – | | – | | – | | – | | – | | – | | – | |
| Prices sourced from observable data or market corroboration | 49 | | 58 | | – | | – | | – | | – | | 107 | |
| Prices based on models and other valuation methods | (444 | ) | (459 | ) | (320 | ) | (218 | ) | (186 | ) | (570 | ) | (2,197 | ) |
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| | (395 | ) | (401 | ) | (320 | ) | (218 | ) | (186 | ) | (570 | ) | (2,090 | ) |
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| | | | | | | | | | | | | | $ million | |
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| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
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| Prices actively quoted | – | | – | | – | | – | | – | | – | | – | |
| Prices sourced from observable data or market corroboration | 51 | | 28 | | – | | – | | – | | – | | 79 | |
| Prices based on models and other valuation methods | (674 | ) | (542 | ) | (426 | ) | (231 | ) | (182 | ) | (565 | ) | (2,620 | ) |
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| | (623 | ) | (514 | ) | (426 | ) | (231 | ) | (182 | ) | (565 | ) | (2,541 | ) |
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The net change in fair value of contracts based on models and other valuation methods during the year is a gain of $423 million (2005 loss of $1,773 million).
Sensitivity analysis
Detailed below for the natural gas embedded derivatives is a sensitivity of the fair value to immediate 10% favourable and adverse changes in the key assumptions.
| | At 31 December 2006 | | At 31 December 2005 | |
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| Remaining contract terms | 2 to 12 years | | 3 to 13 years | |
| Contractual / notional amount | 4,968 million therms | | 8,220 million therms | |
| Discount rate – nominal risk free | 4.5 | % | 4.5 | % |
| Fair value asset (liability) | $(2,171) million | | $(2,590) million | |
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Back to Contents
36 Derivative financial instruments continued
The reduction in notional contract gas volumes compared to 2005 was in part due to deliveries during the year but additionally due to the termination of a contract to supply 1,822 million therms from 2008-2018.
| | | | | | | | | | | | | | | | $ million | |
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| | | | Gas oil and | | | | Discount | | | | Gas oil and | | | | Discount | |
| | Gas price | | fuel oil price | | Power price | | rate | | Gas price | | fuel oil price | | Power price | | rate | |
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| Favourable 10% change | 332 | | 7 | | 45 | | 31 | | 408 | | 30 | | (63 | ) | 34 | |
| Unfavourable 10% change | (341 | ) | (7 | ) | (41 | ) | (32 | ) | (427 | ) | (45 | ) | 58 | | (34 | ) |
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These sensitivities are hypothetical and should not be considered to be predictive of future performance. Changes in fair value generally cannot be extrapolated because the relationship of change in assumption to change in fair value may not be linear. Also, in this table, the effect of a variation in a particular assumption on the fair value of the embedded derivatives is calculated independently of any change in another assumption. In reality, changes in one factor may contribute to changes in another, which may magnify or counteract the sensitivities. Furthermore, the estimated fair values as disclosed should not be considered indicative of future earnings on these contracts.
The fair value gain (loss) on embedded derivatives is shown below.
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| | 2006 | | 2005 | |
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| Natural gas and LNG embedded derivatives | 604 | | (2,034 | ) |
| Interest rate embedded derivatives | 4 | | (13 | ) |
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| Fair value gain (loss) | 608 | | (2,047 | ) |
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The fair value gain (loss) in the above table includes $179 million of exchange losses (2005 $115 million of exchange gains) arising on transactions which are denominated in a currency other than the functional currency of an individual operating unit.
Embedded derivative liabilities denominated in currencies other than the functional currency of individual operating units are summarized below.
| | | | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | Currency of denomination | | | | | | | | Currency of denomination | |
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| | | | | | | | Other | | | | | | | | | | Other | | | |
| | US dollar | | Sterling | | Euro | | currencies | | Total | | US dollar | | Sterling | | Euro | | currencies | | Total | |
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| Functional currency | | | | | | | | | | | | | | | | | | | | |
| US dollar | – | | (1,003 | ) | – | | – | | (1,003 | ) | – | | – | | – | | – | | – | |
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Cash flow hedges
At 31 December, the group held forward currency contracts, cylinders and options which were being used to hedge the foreign currency risk of highly probable transactions. The effective portion of the change in fair value of the hedging instrument is recognized directly in equity, whilst the ineffective portion is recognized in profit or loss. When the hedged transaction occurs, the gain or loss on the hedging instrument is transferred out of equity to either profit or loss or the carrying value of assets, as appropriate. If the forecast transaction is no longer expected to occur, the gain or loss previously recognized in equity is transferred to profit or loss. The hedges were assessed to be highly effective.
An analysis of the changes in net fair value is shown below.
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| | 2006 | | 2005 | |
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| Fair value of cash flow hedges at 1 January | (38 | ) | 198 | |
| Change in fair value during the year | 398 | | (191 | ) |
| Fair value recognized in income statement during the year | (168 | ) | (8 | ) |
| Fair value on capital expenditure hedging recycled into carrying value of assets during the year | (6 | ) | (37 | ) |
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| Fair value of cash flow hedges at 31 December | 186 | | (38 | ) |
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The forward currency contracts and cylinders primarily cover the purchase of sterling and euros for US dollars, with 85% of such contracts due to mature within the next year.
Fair value hedges
At 31 December, the group held interest rate and currency swap contracts as fair value hedges of the interest rate risk on fixed rate debt issued by the group. These hedges were assessed to be highly effective.
The interest rate and currency swaps have an average maturity of 2 to 3 years, and are used to convert sterling, euro, Swiss franc and Australian dollar denominated borrowings into US dollar floating rate debt.
Hedges of net investments in foreign entities
At 31 December, the group held currency swap contracts as a hedge of a long-term investment in a UK subsidiary. The hedge was assessed to be highly effective. At 31 December 2006, the hedge had a fair value of $107 million (2005 $63 million) and the gain on the hedge recognized in equity was $105 million (2005 $58 million). US dollars have been sold forward for sterling purchased, with a maturity of 2 to 3 years.
Back to Contents
37 Derivative financial instruments (UK GAAP)
The following information for 2004 shows certain disclosures required by UK GAAP (FRS 13 ‘Derivatives and other Financial Instruments: Disclosures’).
The group uses derivative financial instruments (derivatives) to manage certain exposures to fluctuations in foreign currency exchange rates and interest rates and to manage some of its margin exposure from changes in oil, natural gas and power prices. Derivatives are also traded in conjunction with these risk management activities.
The purpose for which a derivative contract is used is identified at inception. To qualify as a derivative for risk management, the contract must be in accordance with established guidelines that ensure it is effective in achieving its objective. All contracts not identified at inception as being for the purpose of risk management are designated as being held for trading purposes and accounted for using the fair value method, as are all oil price derivatives.
The group accounts for derivatives using the following methods:
Fair value method
Derivatives are carried on the balance sheet at fair value (‘marked-to-market’), with changes in that value recognized in earnings of the period. This method is used for all derivatives that are held for trading purposes. Interest rate contracts traded by the group include futures, swaps, options and swaptions. Foreign exchange contracts traded include forwards and options. Oil, natural gas and power price contracts traded include swaps, options and futures.
Accrual method
Amounts payable or receivable in respect of derivatives are recognized ratably in earnings over the period of the contracts. This method is used for derivatives held to manage interest rate risk. These are principally swap agreements used to manage the balance between fixed and floating interest rates on long-term finance debt. Other derivatives held for this purpose may include swaptions and futures contracts. Amounts payable or receivable in respect of these derivatives are recognized as adjustments to interest expense over the period of the contracts. Changes in the derivative’s fair value are not recognized.
Deferral method
Gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. This method is used for derivatives used to convert non-US dollar borrowings into US dollars, to hedge significant non-US dollar firm commitments or anticipated transactions, and to manage some of the group’s exposure to natural gas and power price fluctuations. Derivatives used to convert non-US dollar borrowings into US dollars include foreign currency swap agreements and forward contracts. Gains and losses on these derivatives are deferred and recognized on maturity of the underlying debt, together with the matching loss or gain on the debt. Derivatives used to hedge significant non-US dollar transactions include foreign currency forward contracts and options and to hedge natural gas and power price exposures include swaps, futures and options. Gains and losses on these contracts and option premiums paid are also deferred and recognized in the income statement or as adjustments to carrying amounts, as appropriate, when the hedged transaction occurs.
Where derivatives used to manage interest rate risk or to convert non-US dollar debt or to hedge other anticipated cash flows are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying debt or hedged transaction. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement, together with any gain or loss on the terminated item.
Risk management
Gains and losses on derivatives used for risk management purposes are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement, together with any gain or loss on the terminated item. Where such derivatives used for hedging purposes are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying hedged item. The unrecognized and carried-forward gains and losses on derivatives used for hedging, and the movements therein, are shown in the following table.
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| | Unrecognized | | Carried forward in the balance sheet | |
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| | Gains | | Losses | | Total | | Gains | Losses | | Total | |
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| Gains and losses at 1 January 2004 | 331 | | (130 | ) | 201 | | 1,003 | (425 | ) | 578 | |
| of which accounted for in income in 2004 | 98 | | (28 | ) | 70 | | 438 | (75 | ) | 363 | |
| Gains and losses at 31 December 2004 | 487 | | (408 | ) | 79 | | 1,063 | (364 | ) | 699 | |
| of which expected to be recognized in income in 2005 | 259 | | (267 | ) | (8 | ) | 265 | (77 | ) | 188 | |
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Trading activities
The group maintains active trading positions in a variety of derivatives. This activity is undertaken in conjunction with risk management activities. Derivatives held for trading purposes are marked-to-market and any gain or loss recognized in the income statement. For traded derivatives, many positions have been neutralized, with trading initiatives being concluded by taking opposite positions to fix a gain or loss, thereby achieving a zero net market risk.
The group measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using value-at-risk techniques. These techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of the end-of-day exposures and the history of one-day price movements over the previous 12 months, together with the correlation of these price movements. The potential movement in fair values is expressed to three standard deviations, which is equivalent to a 99.7% confidence level. This means that, in broad terms, one would expect to see an increase or a decrease in fair values greater than the value at risk on only one occasion per year if the portfolio were left unchanged.
Back to Contents
37 Derivative financial instruments (UK GAAP) continued
The group calculates value at risk on all instruments that are held for trading purposes and that therefore give an exposure to market risk. The value-at-risk model takes account of derivative financial instruments such as interest rate forward and futures contracts, swap agreements, options and swaptions; foreign exchange forward and futures contracts, swap agreements and options; and oil, natural gas and power price futures, swap agreements and options. Financial assets and liabilities and physical crude oil and refined products that are treated as trading positions are also included in these calculations. The value-at-risk calculation for oil, natural gas and power price exposure also includes cash-settled commodity contracts such as forward contracts.
The following table shows values at risk for trading activities.
| | | | | | | | $ million | |
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| | High | | Low | | Average | | Year end | |
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| Interest rate trading | 1 | | – | | – | | – | |
| Foreign exchange trading | 4 | | 1 | | 1 | | 1 | |
| Oil price trading | 55 | | 18 | | 29 | | 45 | |
| Natural gas price trading | 42 | | 11 | | 23 | | 18 | |
| Power price trading | 18 | | 2 | | 8 | | 7 | |
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The presentation of trading results shown in the table below includes certain activities of BP’s trading units that involve the use of derivative financial instruments in conjunction with physical and paper trading of oil, natural gas and power. It is considered that a more comprehensive representation of the group’s oil, natural gas and power price trading activities is given by aggregating the gain or loss on such derivatives together with the gain or loss arising from the physical and paper trades to which they relate, representing the net result of the trading portfolio.
| | $ million | |
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| | Net gain (loss) | |
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| Interest rate trading | 4 | |
| Foreign exchange trading | 136 | |
| Oil price trading | 1,371 | |
| Natural gas price trading | 461 | |
| Power price trading | 160 | |
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| | 2,132 | |
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38 Finance debt
| | | | | | | | | | | | $ million | |
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| | | | | | 2006 | | | | | | 2005 | |
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| | Within | | After | | | | Within | | After | | | |
| | 1 year | a | 1 year | | Total | | 1 year | a | 1 year | | Total | |
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| Bank loans | 543 | | 806 | | 1,349 | | 155 | | 547 | | 702 | |
| Other loans | 12,321 | | 9,525 | | 21,846 | | 8,717 | | 8,962 | | 17,679 | |
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| Total borrowings | 12,864 | | 10,331 | | 23,195 | | 8,872 | | 9,509 | | 18,381 | |
| Net obligations under finance leases | 60 | | 755 | | 815 | | 60 | | 721 | | 781 | |
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| | 12,924 | | 11,086 | | 24,010 | | 8,932 | | 10,230 | | 19,162 | |
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| a | Amounts due within one year include current maturities of long-term debt. |
Included within Other loans repayable within one year above are US Industrial Revenue/Municipal Bonds of $2,744 million (2005 $2,462 million) with maturity periods ranging from 1 to 34 years. They are classified as repayable within one year as the bondholders typically have the option to tender these bonds for repayment on interest reset dates. Any bonds that are tendered are usually remarketed and BP has not experienced any significant repurchases. BP considers these bonds to represent long-term funding when assessing the maturity profile of its finance debt and they are reflected as such in the borrowings repayment schedule below. Similar treatment is applied for loans associated with long-term gas supply contracts totalling $1,976 million (2005 $992 million) that mature over 10 years.
At 31 December 2006, the group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,700 million, of which $4,300 million are in place for at least 5 years (2005 $4,500 million all expiring in 2006). These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. Certain of these facilities support the group’s commercial paper programme.
At 31 December 2006, the group’s share of third-party finance debt of jointly controlled entities and associates was $4,942 million(2005 $3,266 million) and $1,143 million (2005 $970 million) respectively. These amounts are not reflected in the group’s debt on the balance sheet.
We have in place a European Debt Issuance Programme (DIP) under which the group may raise $10 billion of debt for maturities of one month or longer. At 31 December 2006 the amount drawn down against the DIP was $7,893 million. In addition, the group has in place a US Shelf Registration under which it may raise $10 billion of debt with maturities of one month or longer. At 31 December 2006 there had not been any draw-down.
Back to Contents
38 Finance debt continued
| Analysis of borrowings by year of expected repayment | | | $ million | |
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| | 2006 | | 2005 | |
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| | Bank loans | | Other loans | | Total | | Bank loans | | Other loans | | Total | |
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| Due after 10 years | 153 | | 3,202 | | 3,355 | | – | | 2,842 | | 2,842 | |
| Due within 10 years | 90 | | 62 | | 152 | | 18 | | 203 | | 221 | |
| 9 years | 97 | | 329 | | 426 | | 21 | | 182 | | 203 | |
| 8 years | 90 | | 301 | | 391 | | 24 | | 188 | | 212 | |
| 7 years | 82 | | 318 | | 400 | | 26 | | 558 | | 584 | |
| 6 years | 74 | | 896 | | 970 | | 34 | | 446 | | 480 | |
| 5 years | 131 | | 674 | | 805 | | 35 | | 537 | | 572 | |
| 4 years | 34 | | 653 | | 687 | | 35 | | 2,223 | | 2,258 | |
| 3 years | 28 | | 4,081 | | 4,109 | | 98 | | 2,219 | | 2,317 | |
| 2 years | 27 | | 3,626 | | 3,653 | | 256 | | 3,018 | | 3,274 | |
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| | 806 | | 14,142 | | 14,948 | | 547 | | 12,416 | | 12,963 | |
| 1 year | 543 | | 7,704 | | 8,247 | | 155 | | 5,263 | | 5,418 | |
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| | 1,349 | | 21,846 | | 23,195 | | 702 | | 17,679 | | 18,381 | |
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Interest rates
The weighted average interest rate on finance debt is 5%.
The proportion of floating rate debt at 31 December 2006 was 73% of total finance debt outstanding. Aside from debt issued in the US municipal bond markets, interest rates on floating rate debt denominated in US dollars are linked principally to the London Inter-Bank Offer Rate (LIBOR), while rates on debt in other currencies are based on local market equivalents. The group monitors interest rate risk using a process of sensitivity analysis. Assuming no changes to the finance debt and related hedge balances, it is estimated that a change of 1% in the general level of interest rates on 1 January 2007 would change 2007 profit before tax by approximately $180 million.
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| | Fixed rate | | Floating rate | | | |
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| | Weighted
average
interest | | Weighted
average
time for
which rate | | | | Weighted
average
interest | | | | | |
| | rate | | is fixed | | Amount | | rate | | Amount | | Total | |
| | % | | Years | | $ million | | % | | $ million | | $ million | |
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| | | | | | | | | | | | 2006 | |
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| US dollar | 5 | | 3 | | 5,998 | | 6 | | 17,055 | | 23,053 | |
| Sterling | – | | – | | – | | 5 | | 35 | | 35 | |
| Euro | 3 | | 8 | | 61 | | 4 | | 134 | | 195 | |
| Other currencies | 7 | | 8 | | 299 | | 8 | | 428 | | 727 | |
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| | | | | | 6,358 | | | | 17,652 | | 24,010 | |
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| | 2005 | |
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| US dollar | 7 | | 11 | | 665 | | 5 | | 18,073 | | 18,738 | |
| Sterling | – | | – | | – | | 6 | | 76 | | 76 | |
| Euro | – | | – | | – | | 3 | | 150 | | 150 | |
| Other currencies | 9 | | 14 | | 157 | | 12 | | 41 | | 198 | |
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| | | | | | 822 | | | | 18,340 | | 19,162 | |
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| | | | | | | | | | | | | |
| A further analysis of interest rates on total borrowings, excluding finance lease obligations, at 31 December, is given below. | |
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| | Weighted average | | | | | |
| | interest rate | | | | | |
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| | 2006 | | 2005 | | 2006 | | 2005 | |
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| Bank and other loans – long term | | | | | | | | |
| US dollar | 6 | | 5 | | 9,888 | | 9,178 | |
| Sterling | 5 | | 7 | | 35 | | 29 | |
| Euros | 4 | | 5 | | 177 | | 144 | |
| Other currencies | 7 | | 9 | | 231 | | 158 | |
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| | | | | | 10,331 | | 9,509 | |
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| Bank and other loans – short term | | | | | | | | |
| Current maturities of long-term debt | | | | | 3,078 | | 3,007 | |
| Commercial paper | 5 | | 4 | | 4,167 | | 1,911 | |
| US Industrial Revenue/Municipal bonds | 4 | | 4 | | 2,744 | | 2,462 | |
| Bank loans and other borrowings | 6 | | 7 | | 2,875 | | 1,492 | |
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| | | | | | 12,864 | | 8,872 | |
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| | | | | | 23,195 | | 18,381 | |
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Back to Contents
38 Finance debt continued
Finance leases
The group uses finance leases to acquire property, plant and equipment. These leases have terms of renewal but no purchase options and escalation clauses. Renewals are at the option of the lessee. Future minimum lease payments under finance leases are set out below.
| | $ million | |
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| | 2006 | | 2005 | |
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| Minimum future lease payments payable within | | | | |
| 1 year | 82 | | 78 | |
| 2 to 5 years | 376 | | 320 | |
| Thereafter | 873 | | 838 | |
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| | 1,331 | | 1,236 | |
| Less finance charges | 516 | | 455 | |
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| Net obligations | 815 | | 781 | |
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| Of which – payable within 1 year | 60 | | 60 | |
| – payable within 2 to 5 years | 164 | | 133 | |
| – payable thereafter | 591 | | 588 | |
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Fair values
For 2006, the estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the year from 31 December 2006, whereas in the balance sheet the amount would be reported under current liabilities. Long-term borrowings also include US Industrial Revenue/Municipal Bonds and loans associated with long-term gas supply contracts classified on the balance sheet as current liabilities.
The carrying value of the group’s short-term borrowings, comprising mainly commercial paper, bank loans and overdrafts, approximates their fair value. The fair value of the group’s long-term borrowings and finance lease obligations is estimated using quoted prices or, where these are not available, discounted cash flow analyses based on the group’s current incremental borrowing rates for similar types and maturities of borrowing.
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| | | | 2006 | | | | 2005 | |
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| | | | Carrying | | | | Carrying | |
| | Fair value | | amount | | Fair value | | amount | |
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| Short-term borrowings | 7,040 | | 7,040 | | 3,297 | | 3,297 | |
| Long-term borrowings | 16,201 | | 16,155 | | 15,313 | | 15,084 | |
| Net obligations under finance leases | 832 | | 815 | | 803 | | 781 | |
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| Total finance debt | 24,073 | | 24,010 | | 19,413 | | 19,162 | |
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39 Analysis of changes in net debt
Net debt is current and non-current finance debt less cash and cash equivalents. The net debt ratio is the ratio of net debt to net debt plus total equity. The net debt ratio at 31 December 2006 was 20% (2005 17%).
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| | 2006 | | 2005 | |
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| | | | Cash and | | | | | | Cash and | | | |
| | Finance | | cash | | Net | | Finance | | cash | | Net | |
| Movement in net debt | debt | | equivalents | | debt | | debt | | equivalents | | debt | |
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| At 1 January | (19,162 | ) | 2,960 | | (16,202 | ) | (23,091 | ) | 1,359 | | (21,732 | ) |
| Adoption of IAS 39 | – | | – | | – | | (147 | ) | – | | (147 | ) |
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| Restated | (19,162 | ) | 2,960 | | (16,202 | ) | (23,238 | ) | 1,359 | | (21,879 | ) |
| Exchange adjustments | (172 | ) | 47 | | (125 | ) | (44 | ) | (88 | ) | (132 | ) |
| Debt acquired | (13 | ) | – | | (13 | ) | – | | – | | – | |
| Net cash flow | (4,049 | ) | (417 | ) | (4,466 | ) | 3,803 | | 1,689 | | 5,492 | |
| Fair value hedge adjustment | (581 | ) | – | | (581 | ) | 171 | | – | | 171 | |
| Other movements | (33 | ) | – | | (33 | ) | 146 | | – | | 146 | |
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| At 31 December | (24,010 | ) | 2,590 | | (21,420 | ) | (19,162 | ) | 2,960 | | (16,202 | ) |
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| Equity | | | | | 85,465 | | | | | | 80,450 | |
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Back to Contents
40 Provisions
| $ million | |
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| | | | | | | Litigation | | | |
| | | Decommissioning | | Environmental | | and other | | Total | |
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| At 1 January 2006 | 6,450 | | 2,311 | | 2,795 | | 11,556 | |
| Exchange adjustments | 13 | | 31 | | 44 | | 88 | |
| New or increased provisions | 2,142 | | 423 | | 1,611 | | 4,176 | |
| Write-back of unused provisions | – | | (355 | ) | (270 | ) | (625 | ) |
| Unwinding of discount | 153 | | 45 | | 47 | | 245 | |
| Utilization | (179 | ) | (324 | ) | (1,068 | ) | (1,571 | ) |
| Deletions | (214 | ) | (4 | ) | (7 | ) | (225 | ) |
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| At 31 December 2006 | 8,365 | | 2,127 | | 3,152 | | 13,644 | |
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| Of which | – expected to be incurred within 1 year | 324 | | 444 | | 1,164 | | 1,932 | |
| | – expected to be incurred in more than 1 year | 8,041 | | 1,683 | | 1,988 | | 11,712 | |
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| | | | | | | Litigation | | | |
| | | Decommissioning | | Environmental | | and other | | Total | |
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| At 1 January 2006 | 5,572 | | 2,457 | | 1,570 | | 9,599 | |
| Exchange adjustments | (38 | ) | (32 | ) | (35 | ) | (105 | ) |
| New or increased provisions | 1,023 | | 565 | | 1,964 | | 3,552 | |
| Write-back of unused provisions | – | | (335 | ) | (86 | ) | (421 | ) |
| Unwinding of discount | 122 | | 47 | | 32 | | 201 | |
| Utilization | (128 | ) | (366 | ) | (650 | ) | (1,144 | ) |
| Deletions | (101 | ) | (25 | ) | – | | (126 | ) |
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| At 31 December 2006 | 6,450 | | 2,311 | | 2,795 | | 11,556 | |
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| Of which | – expected to be incurred within 1 year | 162 | | 489 | | 951 | | 1,602 | |
| | – expected to be incurred in more than 1 year | 6,288 | | 1,822 | | 1,844 | | 9,954 | |
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The group makes full provision for the future cost of decommissioning oil and natural gas production facilities and related pipelines on a discounted basis on the installation of those facilities. The provision for the costs of decommissioning these production facilities and pipelines at the end of their economic lives has been estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2005 2.0%) . These costs are expected to be incurred over the next 30 years. While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of incurring these costs.
Provisions for environmental remediation are made when a clean-up is probable and the amount reasonably determinable. Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or closure of inactive sites. The provision for environmental liabilities has been estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2005 2.0%) . The majority of these costs are expected to be incurred over the next 10 years. The extent and cost of future remediation programmes are inherently difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions, and also the group’s share of liability.
The group also holds provisions for litigation, expected rental shortfalls on surplus properties, and sundry other liabilities. Included within the new or increased provisions made for 2006 is an amount of $425 million (2005 $1,200 million) in respect of the Texas City incident of which a total of $1,355 million has been disbursed to claimants ($863 million in 2006 and $492 million in 2005).
To the extent that these liabilities are not expected to be settled within the next three years, the provisions are discounted using either a nominal discount rate of 4.5% (2005 4.5%) or a real discount rate of 2.0% (2005 2.0%), as appropriate.
41 Pensions and other post-retirement benefits
Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as the employees’ pensionable salary and length of service. Defined benefit plans may be externally funded or unfunded. The assets of funded plans are generally held in separately administered trusts.
In particular, in the UK the primary pension arrangement is a funded final salary pension plan which remains open to new employees. Retired employees draw the majority of their benefit as an annuity.
In the US, a range of retirement arrangements are provided. These include a funded final salary pension plan for certain heritage employees and a cash balance arrangement for new hires. Retired US employees typically take their pension benefit in the form of a lump sum payment. US employees are also eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions.
Contributions to funded defined benefit plans are based on advice from independent actuaries using actuarial methods, the objective of which is to provide adequate funds to meet pension obligations as they fall due. During 2006, contributions of $438 million (2005 $340 million and 2004 $249 million) and $181 million (2005 $279 million and 2004 $30 million) were made to the UK plans and US plans respectively. In addition, contributions of $136 million (2005 $140 million and 2004 $116 million) were made to other funded defined benefit plans. The aggregate level of contributions in 2007 is expected to be approximately $750 million.
Certain group companies, principally in the US, provide post-retirement healthcare and life insurance benefits to their retired employees and dependants. The entitlement to these benefits is usually based on the employee remaining in service until retirement age and completion of a minimum period of service. The plans are funded to a limited extent.
The cost of providing pensions and other post-retirement benefits is assessed annually by independent actuaries using the projected unit credit method. The date of the most recent actuarial review was 31 December 2006.
Back to Contents
41 Pensions and other post-retirement benefits continued
The material financial assumptions used for estimating the benefit obligations of the various plans are set out below. The assumptions used to evaluate accrued pension and other post-retirement benefits at 31 December in any year are used to determine pension and other post-retirement expense for the following year, that is, the assumptions at 31 December 2006 are used to determine the pension liabilities at that date and the pension cost for 2007.
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| Financial assumptions | UK | | USA | | Other | |
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| | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
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| Discount rate for pension plan liabilities | 5.1 | | 4.75 | | 5.25 | | 5.7 | | 5.50 | | 5.75 | | 4.8 | | 4.00 | | 5.00 | |
| Discount rate for post-retirement benefit plans | n/a | | n/a | | n/a | | 5.9 | | 5.50 | | 5.75 | | n/a | | n/a | | n/a | |
| Rate of increase in salaries | 4.7 | | 4.25 | | 4.00 | | 4.2 | | 4.25 | | 4.00 | | 3.6 | | 3.25 | | 4.00 | |
| Rate of increase for pensions in payment | 2.8 | | 2.50 | | 2.50 | | nil | | nil | | nil | | 1.8 | | 1.75 | | 2.50 | |
| Rate of increase in deferred pensions | 2.8 | | 2.50 | | 2.50 | | nil | | nil | | nil | | 1.1 | | 1.00 | | 2.50 | |
| Inflation | 2.8 | | 2.50 | | 2.50 | | 2.4 | | 2.50 | | 2.50 | | 2.2 | | 2.00 | | 2.50 | |
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In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice in the countries in which we provide pensions, and have been chosen with regard to the latest available published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension liabilities are in the UK, the US and Germany, where our assumptions are as follows:
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| Mortality assumptions | UK | | USA | | Germany | |
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| | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | |
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| Life expectancy at age 60 for a male currently aged 60 | 23.9 | | 23.0 | | 23.0 | | 24.2 | | 21.9 | | 21.9 | | 22.2 | | 22.1 | | 20.3 | |
| Life expectancy at age 60 for a female currently aged 60 | 26.8 | | 26.0 | | 26.0 | | 26.0 | | 25.6 | | 25.6 | | 26.9 | | 26.7 | | 25.4 | |
| Life expectancy at age 60 for a male currently aged 40 | 25.0 | | 23.9 | | 23.9 | | 25.8 | | 21.9 | | 21.9 | | 25.2 | | 25.0 | | 20.3 | |
| Life expectancy at age 60 for a female currently aged 40 | 27.8 | | 26.9 | | 26.9 | | 26.9 | | 25.6 | | 25.6 | | 29.6 | | 29.4 | | 25.4 | |
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| The assumed future US healthcare cost trend rate is as follows: | | | | | | | | | | | | | % | |
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| | | | | | | | | | | | | | 2013 and | |
| | | | | | | | | | | | | | subsequent | |
| Assumed future US healthcare cost trend rate | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | years | |
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| Beneficiaries aged under 65 | 8.0 | | 7.5 | | 7.0 | | 6.5 | | 6.0 | | 5.5 | | 5.0 | |
| Beneficiaries aged over 65 | 10.0 | | 9.5 | | 8.5 | | 7.5 | | 6.5 | | 5.5 | | 5.0 | |
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BP’s post-retirement medical plans in the US provide amongst other things prescription drug coverage for Medicare-eligible retirees. The group’s obligation for other post-retirement benefits reflects the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The provisions of the Act provide for a federal subsidy for plans that provide prescription drug benefits and meet certain qualifications, and alternatively would allow prescription drug plan sponsors to co-ordinate with the Medicare benefit. BP reflects the impact of the legislation by reducing its actuarially determined obligation for post-retirement benefits and reducing the net cost for post-retirement benefits. For the year ended 31 December 2006 the reduction in net cost was $40 million (2005 $41 million).
Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligation of the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management.
A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term with an acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are highly diversified. The long-term asset allocation policy for the major plans is as follows:
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| | Policy range | |
| Asset category | % | |
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| Total equity | 55– 85 | |
| Fixed income/cash | 15– 35 | |
| Property/real estate | 0– 10 | |
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Some of the group’s pension funds use derivatives to manage their asset mix and the level of risk. The group’s main pension funds do not directly invest in either securities or property/real estate of the company or of any subsidiary.
Return on asset assumptions reflect the group’s expectations built up by asset class and by plan. The group’s expectation is derived from a combination of historical returns over the long term and the forecasts of market professionals.
Back to Contents
41 Pensions and other post-retirement benefits continued
The expected long-term rates of return and market values of the various categories of asset held by the significant defined benefit plans at 31 December are set out below.
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| | 2006 | | 2005 | | 2004 | |
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| | Expected | | | | Expected | | | | Expected | | | |
| | long-term | | Market | | long-term | | Market | | long-term | | Market | |
| | rate of return | | value | | rate of return | | value | | rate of return | | value | |
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| | % | | $ million | | % | | $ million | | % | | $ million | |
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| UK pension plans | | | | | | | | | | | | |
| Equities | 7.5 | | 23,631 | | 7.50 | | 18,465 | | 7.50 | | 17,329 | |
| Bonds | 4.7 | | 3,881 | | 4.25 | | 2,719 | | 4.50 | | 2,859 | |
| Property | 6.5 | | 1,370 | | 6.50 | | 1,097 | | 6.50 | | 1,660 | |
| Cash | 3.8 | | 379 | | 3.50 | | 1,001 | | 4.00 | | 459 | |
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| | 7.0 | | 29,261 | | 7.00 | | 23,282 | | 7.00 | | 22,307 | |
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| US pension plans | | | | | | | | | | | | |
| Equities | 8.5 | | 6,528 | | 8.50 | | 5,961 | | 8.50 | | 6,043 | |
| Bonds | 5.0 | | 1,371 | | 4.75 | | 1,079 | | 4.75 | | 1,057 | |
| Property | 8.0 | | 15 | | 8.00 | | 21 | | 8.00 | | 28 | |
| Cash | 3.2 | | 41 | | 3.00 | | 256 | | 3.00 | | 55 | |
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| | 8.0 | | 7,955 | | 8.00 | | 7,317 | | 8.00 | | 7,183 | |
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| US other post-retirement benefit plans | | | | | | | | | | | | |
| Equities | 8.5 | | 19 | | 8.50 | | 20 | | 8.50 | | 21 | |
| Bonds | 5.0 | | 7 | | 4.75 | | 8 | | 4.75 | | 9 | |
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| | 7.5 | | 26 | | 7.25 | | 28 | | 7.25 | | 30 | |
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| Other plans | | | | | | | | | | | | |
| Equities | 7.6 | | 1,158 | | 7.50 | | 991 | | 8.00 | | 933 | |
| Bonds | 4.6 | | 1,199 | | 4.00 | | 943 | | 4.25 | | 857 | |
| Property | 4.7 | | 120 | | 5.75 | | 130 | | 5.25 | | 114 | |
| Cash | 3.0 | | 191 | | 1.50 | | 216 | | 3.50 | | 288 | |
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| | 5.8 | | 2,668 | | 5.50 | | 2,280 | | 6.00 | | 2,192 | |
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The assumed rate of investment return and discount rate have a significant effect on the amounts reported. A one-percentage-point change in these assumptions for the group’s plans would have had the following effects:
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| | Increase | | Decrease | |
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| Investment return | | | | |
| Effect on pension and other post-retirement benefit expense in 2007 | (383 | ) | 383 | |
| Discount rate | | | | |
| Effect on pension and other post-retirement benefit expense in 2007 | (52 | ) | 75 | |
| Effect on pension and other post-retirement benefit obligation at 31 December 2006 | (5,013 | ) | 6,433 | |
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The assumed US healthcare cost trend rate has a significant effect on the amounts reported. A one-percentage-point change in the assumed US healthcare cost trend rate would have had the following effects:
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| | One-percentage point | |
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| | Increase | | Decrease | |
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| Effect on US other post-retirement benefit expense in 2007 | 31 | | (25 | ) |
| Effect on US other post-retirement obligation at 31 December 2006 | 349 | | (289 | ) |
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Back to Contents
41 Pensions and other post-retirement benefits continued
| | $ million | |
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| | | | | | US | | | | | |
| | UK | | US | | other post- | | | | | |
| | pension | | pension | | retirement | | | | | |
| Analysis of the amount charged to profit before interest and taxation | plans | | plans | | benefit plans | | Other plans | | Total | |
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| Current service cost | 432 | | 216 | | 42 | | 139 | | 829 | |
| Past service cost | (74 | ) | 38 | | – | | 39 | | 3 | |
| Settlement, curtailment and special termination benefits | 4 | | – | | – | | 227 | | 231 | |
| Payments to defined contribution plans | – | | 161 | | – | | 16 | | 177 | |
|
|
|
|
|
|
|
|
|
|
|
| Total operating charge a | 362 | | 415 | | 42 | | 421 | | 1,240 | |
|
|
|
|
|
|
|
|
|
|
|
| Analysis of the amount credited (charged) to other finance expense | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Expected return on plan assets | 1,711 | | 564 | | 2 | | 133 | | 2,410 | |
| Interest on plan liabilities | (1,006 | ) | (423 | ) | (186 | ) | (325 | ) | (1,940 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Other finance income (expense) | 705 | | 141 | | (184 | ) | (192 | ) | 470 | |
|
|
|
|
|
|
|
|
|
|
|
| Analysis of the amount recognized in the statement of recognized income and expense | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Actual return less expected return on pension plan assets | 1,305 | | 521 | | – | | 141 | | 1,967 | |
| Change in assumptions underlying the present value of the plan liabilities | 114 | | 195 | | 111 | | 352 | | 772 | |
| Experience gains and losses arising on the plan liabilities | (24 | ) | 17 | | 80 | | (197 | ) | (124 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Actuarial gain recognized in statement of recognized income and expense | 1,395 | | 733 | | 191 | | 296 | | 2,615 | |
|
|
|
|
|
|
|
|
|
|
|
| Movements in benefit obligation during the year | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Benefit obligation at 1 January | 20,063 | | 7,900 | | 3,478 | | 7,414 | | 38,855 | |
| Exchange adjustments | 2,748 | | – | | – | | 632 | | 3,380 | |
| Current service cost | 432 | | 216 | | 42 | | 139 | | 829 | |
| Past service cost | (74 | ) | 38 | | – | | 39 | | 3 | |
| Interest cost | 1,006 | | 423 | | 186 | | 325 | | 1,940 | |
| Curtailment | (20 | ) | – | | – | | – | | (20 | ) |
| Settlement | (22 | ) | – | | – | | – | | (22 | ) |
| Special termination benefits b | 46 | | – | | – | | 227 | | 273 | |
| Contributions by plan participants | 38 | | – | | – | | 5 | | 43 | |
| Benefit payments (funded plans) | (981 | ) | (615 | ) | (4 | ) | (149 | ) | (1,749 | ) |
| Benefit payments (unfunded plans) | – | | (37 | ) | (211 | ) | (321 | ) | (569 | ) |
| Acquisitions | – | | – | | – | | – | | – | |
| Disposals | 143 | | (18 | ) | – | | (7 | ) | 118 | |
| Actuarial gain on obligation | (90 | ) | (212 | ) | (191 | ) | (155 | ) | (648 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Benefit obligation at 31 December | 23,289 | | 7,695 | | 3,300 | | 8,149 | | 42,433 | |
|
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|
|
|
|
|
|
|
|
|
| Movements in fair value of plan assets during the year | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Fair value of plan assets at 1 January | 23,282 | | 7,317 | | 28 | | 2,280 | | 32,907 | |
| Exchange adjustments | 3,325 | | – | | – | | 122 | | 3,447 | |
| Expected return on plan assets c | 1,711 | | 564 | | 2 | | 133 | | 2,410 | |
| Contributions by plan participants | 38 | | – | | – | | 5 | | 43 | |
| Contributions by employers (funded plans) | 438 | | 181 | | – | | 136 | | 755 | |
| Benefit payments (funded plans) | (981 | ) | (615 | ) | (4 | ) | (149 | ) | (1,749 | ) |
| Acquisitions | – | | – | | – | | – | | – | |
| Disposals | 143 | | (13 | ) | – | | – | | 130 | |
| Actuarial gain on plan assets c | 1,305 | | 521 | | – | | 141 | | 1,967 | |
|
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|
|
|
|
|
|
|
|
|
| Fair value of plan assets at 31 December | 29,261 | | 7,955 | | 26 | | 2,668 | | 39,910 | |
|
|
|
|
|
|
|
|
|
|
|
| Surplus (deficit) at 31 December | 5,972 | | 260 | | (3,274 | ) | (5,481 | ) | (2,523 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Represented by | | | | | | | | | | |
| Asset recognized | 6,089 | | 617 | | – | | 47 | | 6,753 | |
| Liability recognized | (117 | ) | (357 | ) | (3,274 | ) | (5,528 | ) | (9,276 | ) |
|
|
|
|
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|
|
|
|
|
|
| | 5,972 | | 260 | | (3,274 | ) | (5,481 | ) | (2,523 | ) |
|
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|
|
|
|
|
|
|
|
|
| The surplus (deficit) may be analysed between funded and unfunded plans as follows | | | | | | | | | | |
| Funded | 6,089 | | 601 | | (30 | ) | (379 | ) | 6,281 | |
| Unfunded | (117 | ) | (341 | ) | (3,244 | ) | (5,102 | ) | (8,804 | ) |
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|
|
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|
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|
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| | 5,972 | | 260 | | (3,274 | ) | (5,481 | ) | (2,523 | ) |
|
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|
|
|
|
|
| The defined benefit obligation may be analysed between funded and unfunded plans as follows | | | | | | | | | | |
| Funded | (23,172 | ) | (7,354 | ) | (56 | ) | (3,047 | ) | (33,629 | ) |
| Unfunded | (117 | ) | (341 | ) | (3,244 | ) | (5,102 | ) | (8,804 | ) |
|
|
|
|
|
|
|
|
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|
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| | (23,289 | ) | (7,695 | ) | (3,300 | ) | (8,149 | ) | (42,433 | ) |
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| | | | | | | | | | | |
| a | Included within production and manufacturing expenses and distribution and administration expenses. |
| b | The charge for special termination benefits represents the increased liability arising as a result of early retirements occuring as part of a restructuring programme in the UK and Europe. |
| c | The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain on plan assets as disclosed above. |
At 31 December 2006 reimbursement balances due from or to other companies in respect of pensions amounted to $479 million reimbursement assets (2005 $465 million) and $71 million reimbursement liabilities (2005 $71 million). These balances are not included as part of the pension liability, but are reflected elsewhere in the group balance sheet.
Back to Contents
41 Pensions and other post-retirement benefits continued
| | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | 2005 | |
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|
|
|
|
|
|
|
|
|
|
| | | | | | US | | | | | |
| | UK | | US | | other post- | | | | | |
| | pension | | pension | | retirement | | | | | |
| Analysis of the amount charged to profit before interest and taxation | plans | | plans | | benefit plans | | Other plans | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Current service cost | 379 | | 216 | | 50 | | 140 | | 785 | |
| Past service cost | 5 | | (10 | ) | (5 | ) | 51 | | 41 | |
| Settlement, curtailment and special termination benefits | 37 | | – | | – | | 10 | | 47 | |
| Payments to defined contribution plans | – | | 158 | | – | | 14 | | 172 | |
|
|
|
|
|
|
|
|
|
|
|
| Total operating charge | 421 | | 364 | | 45 | | 215 | | 1,045 | |
| Innovene operations | (38 | ) | (24 | ) | (3 | ) | (21 | ) | (86 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Continuing operations a | 383 | | 340 | | 42 | | 194 | | 959 | |
|
|
|
|
|
|
|
|
|
|
|
| Analysis of the amount credited (charged) to other finance expense | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Expected return on plan assets | 1,456 | | 557 | | 2 | | 123 | | 2,138 | |
| Interest on plan liabilities | (1,003 | ) | (444 | ) | (207 | ) | (368 | ) | (2,022 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Other finance income (expense) | 453 | | 113 | | (205 | ) | (245 | ) | 116 | |
| Innovene operations | (10 | ) | (5 | ) | 2 | | 10 | | (3 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Continuing operations | 443 | | 108 | | (203 | ) | (235 | ) | 113 | |
|
|
|
|
|
|
|
|
|
|
|
| Analysis of the amount recognized in the statement of recognized income and expense | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Actual return less expected return on pension plan assets | 3,111 | | 96 | | – | | 157 | | 3,364 | |
| Change in assumptions underlying the present value of the plan liabilities | (1,884 | ) | (59 | ) | 236 | | (470 | ) | (2,177 | ) |
| Experience gains and losses arising on the plan liabilities | (14 | ) | (197 | ) | (17 | ) | 16 | | (212 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Actuarial gain (loss) recognized in statement of recognized income and expense | 1,213 | | (160 | ) | 219 | | (297 | ) | 975 | |
|
|
|
|
|
|
|
|
|
|
|
| Movements in benefit obligation during the year | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Benefit obligation at 1 January | 20,399 | | 7,826 | | 3,676 | | 8,044 | | 39,945 | |
| Exchange adjustments | (2,194 | ) | – | | – | | (928 | ) | (3,122 | ) |
| Current service cost | 379 | | 216 | | 50 | | 140 | | 785 | |
| Past service cost | 5 | | (10 | ) | (5 | ) | 51 | | 41 | |
| Interest cost | 1,003 | | 444 | | 207 | | 368 | | 2,022 | |
| Special termination benefits | 37 | | – | | – | | 10 | | 47 | |
| Contributions by plan participants | 37 | | – | | – | | 5 | | 42 | |
| Benefit payments (funded plans) | (922 | ) | (570 | ) | (4 | ) | (116 | ) | (1,612 | ) |
| Benefit payments (unfunded plans) | (1 | ) | (30 | ) | (204 | ) | (314 | ) | (549 | ) |
| Acquisitions | – | | 20 | | 16 | | 3 | | 39 | |
| Disposals | (578 | ) | (252 | ) | (39 | ) | (303 | ) | (1,172 | ) |
| Actuarial (gain) loss on obligation | 1,898 | | 256 | | (219 | ) | 454 | | 2,389 | |
|
|
|
|
|
|
|
|
|
|
|
| Benefit obligation at 31 December | 20,063 | | 7,900 | | 3,478 | | 7,414 | | 38,855 | |
|
|
|
|
|
|
|
|
|
|
|
| Movements in fair value of plan assets during the year | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Fair value of plan assets at 1 January | 22,307 | | 7,183 | | 30 | | 2,192 | | 31,712 | |
| Exchange adjustments | (2,469 | ) | – | | – | | (195 | ) | (2,664 | ) |
| Expected return on plan assets b | 1,456 | | 557 | | 2 | | 123 | | 2,138 | |
| Contributions by plan participants | 37 | | – | | – | | 5 | | 42 | |
| Contributions by employers (funded plans) | 340 | | 279 | | – | | 140 | | 759 | |
| Benefit payments (funded plans) | (922 | ) | (570 | ) | (4 | ) | (116 | ) | (1,612 | ) |
| Acquisitions | – | | 8 | | – | | – | | 8 | |
| Disposals | (578 | ) | (236 | ) | – | | (26 | ) | (840 | ) |
| Actuarial gain on plan assets b | 3,111 | | 96 | | – | | 157 | | 3,364 | |
|
|
|
|
|
|
|
|
|
|
|
| Fair value of plan assets at 31 December | 23,282 | | 7,317 | | 28 | | 2,280 | | 32,907 | |
|
|
|
|
|
|
|
|
|
|
|
| Surplus (deficit) at 31 December | 3,219 | | (583 | ) | (3,450 | ) | (5,134 | ) | (5,948 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Represented by | | | | | | | | | | |
| Asset recognized | 3,240 | | – | | – | | 42 | | 3,282 | |
| Liability recognized | (21 | ) | (583 | ) | (3,450 | ) | (5,176 | ) | (9,230 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | 3,219 | | (583 | ) | (3,450 | ) | (5,134 | ) | (5,948 | ) |
|
|
|
|
|
|
|
|
|
|
|
| The surplus (deficit) may be analysed between funded and unfunded plans as follows | | | | | | | | | | |
| Funded | 3,240 | | (226 | ) | (32 | ) | (476 | ) | 2,506 | |
| Unfunded | (21 | ) | (357 | ) | (3,418 | ) | (4,658 | ) | (8,454 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | 3,219 | | (583 | ) | (3,450 | ) | (5,134 | ) | (5,948 | ) |
|
|
|
|
|
|
|
|
|
|
|
| The defined benefit obligation may be analysed between funded and unfunded plans as follows | | | | | | | | | | |
| Funded | (20,042 | ) | (7,543 | ) | (60 | ) | (2,756 | ) | (30,401 | ) |
| Unfunded | (21 | ) | (357 | ) | (3,418 | ) | (4,658 | ) | (8,454 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | (20,063 | ) | (7,900 | ) | (3,478 | ) | (7,414 | ) | (38,855 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | |
| a | Included within production and manufacturing expenses and distribution and administration expenses. |
| b | The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain on plan assets as disclosed above. |
Back to Contents
41 Pensions and other post-retirement benefits continued
| | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | 2004 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | US | | | | | |
| | UK | | US | | other post- | | | | | |
| | pension | | pension | | retirement | | | | | |
| Analysis of the amount charged to profit before interest and taxation | plans | | plans | | benefit plans | | Other plans | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Current service cost | 363 | | 215 | | 61 | | 118 | | 757 | |
| Past service cost | 5 | | – | | (4 | ) | 38 | | 39 | |
| Settlement, curtailment and special termination benefits | 37 | | – | | – | | 27 | | 64 | |
| Payments to defined contribution plans | – | | 150 | | – | | 12 | | 162 | |
|
|
|
|
|
|
|
|
|
|
|
| Total operating charge | 405 | | 365 | | 57 | | 195 | | 1,022 | |
| Innovene operations | (35 | ) | (25 | ) | (3 | ) | (22 | ) | (85 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Continuing operations a | 370 | | 340 | | 54 | | 173 | | 937 | |
|
|
|
|
|
|
|
|
|
|
|
| Analysis of the amount credited (charged) to other finance expense | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Expected return on plan assets | 1,351 | | 526 | | 2 | | 104 | | 1,983 | |
| Interest on plan liabilities | (981 | ) | (445 | ) | (240 | ) | (346 | ) | (2,012 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Other finance income (expense) | 370 | | 81 | | (238 | ) | (242 | ) | (29 | ) |
| Innovene operations | (6 | ) | (3 | ) | 14 | | 12 | | 17 | |
|
|
|
|
|
|
|
|
|
|
|
| Continuing operations | 364 | | 78 | | (224 | ) | (230 | ) | (12 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Analysis of the amount recognized in the statement of recognized income and expense | | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
| Actual return less expected return on pension plan assets | 818 | | 379 | | – | | 152 | | 1,349 | |
| Change in assumptions underlying the present value of the plan liabilities | (795 | ) | (108 | ) | 495 | | (366 | ) | (774 | ) |
| Experience gains and losses arising on the plan liabilities | 83 | | (22 | ) | 33 | | (562 | ) | (468 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Actuarial gain (loss) recognized in statement of recognized income and expense | 106 | | 249 | | 528 | | (776 | ) | 107 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | |
| a | Included within production and manufacturing expenses and distribution and administration expenses. |
| | |
| | $ million | |
|
|
|
|
|
|
|
|
|
| History of surplus (deficit) and of experience gains and losses | 2006 | | 2005 | | 2004 | | 2003 | |
|
|
|
|
|
|
|
|
|
| Benefit obligation at 31 December | 42,433 | | 38,855 | | 39,945 | | 35,995 | |
| Fair value of plan assets at 31 December | 39,910 | | 32,907 | | 31,712 | | 27,853 | |
|
|
|
|
|
|
|
|
|
| Surplus (deficit) | (2,523 | ) | (5,948 | ) | (8,233 | ) | (8,142 | ) |
|
|
|
|
|
|
|
|
|
| Experience gains and losses on plan liabilities | (124 | ) | (212 | ) | (468 | ) | 873 | |
| Actual return less expected return on pension plan assets | 1,967 | | 3,364 | | 1,349 | | 2,392 | |
| Actual return on plan assets | 4,377 | | 5,502 | | 3,332 | | 3,892 | |
| Actuarial gain recognized in statement of recognized income and expense | 2,615 | | 975 | | 107 | | 76 | |
| Cumulative amount recognized in statement of recognized income and expense | 3,773 | | 1,158 | | 183 | | 76 | |
|
|
|
|
|
|
|
|
|
Estimated future benefit payments
The expected benefit payments, which reflect expected future service, as appropriate, but excluding fund expenses, up until 2016 are as follows:
| | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | US | | | | | |
| | UK | | US | | other post- | | | | | |
| | pension | | pension | | retirement | | | | | |
| | plans | | plans | | benefit plans | | Other plans | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| 2007 | 1,013 | | 619 | | 212 | | 509 | | 2,353 | |
| 2008 | 1,053 | | 650 | | 213 | | 519 | | 2,435 | |
| 2009 | 1,070 | | 673 | | 219 | | 513 | | 2,475 | |
| 2010 | 1,146 | | 695 | | 224 | | 506 | | 2,571 | |
| 2011 | 1,165 | | 714 | | 229 | | 496 | | 2,604 | |
| 2012-2016 | 6,432 | | 3,621 | | 1,156 | | 2,271 | | 13,480 | |
|
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|
|
|
|
|
|
|
|
|
Back to Contents
42 Called up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
|
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|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Issued | Shares (thousand) | | $ million | | Shares (thousand) | | $ million | | Shares (thousand) | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 8% cumulative first preference shares of £1 each | 7,233 | | 12 | | 7,233 | | 12 | | 7,233 | | 12 | |
| 9% cumulative second preference shares of £1 each | 5,473 | | 9 | | 5,473 | | 9 | | 5,473 | | 9 | |
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| | | | 21 | | | | 21 | | | | 21 | |
|
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|
|
|
|
|
|
| Ordinary shares of 25 cents each | | | | | | | | | | | | |
| 1 January | 20,657,045 | | 5,164 | | 21,525,978 | | 5,382 | | 22,122,610 | | 5,531 | |
| Issue of new shares for employee share schemes | 64,854 | | 16 | | 82,144 | | 20 | | 91,512 | | 23 | |
| Issue of ordinary share capital for TNK-BP | 111,151 | | 28 | | 108,629 | | 27 | | 139,096 | | 35 | |
| Repurchase of ordinary share capital | (358,374 | ) | (90 | ) | (1,059,706 | ) | (265 | ) | (827,240 | ) | (207 | ) |
| Other a | 982,625 | | 246 | | – | | – | | – | | – | |
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|
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|
|
|
|
|
|
|
|
| 31 December | 21,457,301 | | 5,364 | | 20,657,045 | | 5,164 | | 21,525,978 | | 5,382 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | 5,385 | | | | 5,185 | | | | 5,403 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Authorized | | | | | | | | | | | | |
| 8% cumulative first preference shares of £1 each | 7,250 | | 12 | | 7,250 | | 12 | | 7,250 | | 12 | |
| 9% cumulative second preference shares of £1 each | 5,500 | | 9 | | 5,500 | | 9 | | 5,500 | | 9 | |
| Ordinary shares of 25 cents each | 36,000,000 | | 9,000 | | 36,000,000 | | 9,000 | | 36,000,000 | | 9,000 | |
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| | | | | | | | | | | | | |
| a | Reclassification in respect of share repurchases in 2005. |
| | |
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.
Repurchase of ordinary share capital
The company purchased 1,334,362,750 ordinary shares (2005 1,059,706,481 and 2004 827,240,360 ordinary shares) for a total consideration of $15,481 million (2005 $11,597 million and 2004 $7,548 million), of which 358,374,000 were for cancellation and 975,988,750 were retained in treasury. At 31 December 2006, 1,946,804,533 shares of nominal value $487 million were held in treasury (2005 982,624,971 shares of nominal value of $246 million). Transaction costs of share repurchases amounted to $83 million (2005 $63 million and 2004 $43 million).
Back to Contents
43 Capital and reserves
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| | | | Share | | Capital | | | |
| | Share | | premium | | redemption | | Merger | |
| | capital | | account | | reserve | | reserve | |
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| At 1 January 2006 | 5,185 | | 7,371 | | 749 | | 27,190 | |
| Currency translation differences (net of tax) | – | | – | | – | | – | |
| Actuarial gain relating to pensions and other post-retirement benefits (net of tax) | – | | – | | – | | – | |
| Issue of ordinary share capital for TNK-BP | 28 | | 1,222 | | – | | – | |
| Available-for-sale investments marked to market (net of tax) | – | | – | | – | | – | |
| Available-for-sale investments recycling (net of tax) | – | | – | | – | | – | |
| Repurchase of ordinary share capital | (90 | ) | – | | 90 | | – | |
| Share-based payments (net of tax) | 16 | | 481 | | – | | 11 | |
| Cash flow hedges marked to market (net of tax) | – | | – | | – | | – | |
| Cash flow hedges recycling (net of tax) | – | | – | | – | | – | |
| Profit for the year | – | | – | | – | | – | |
| Dividends | – | | – | | – | | – | |
| Other c | 246 | | – | | – | | – | |
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| At 31 December 2006 | 5,385 | | 9,074 | | 839 | | 27,201 | |
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| a | For the year ended 31 December 2006, purchases of shares by ESOP trusts amounted to $205 million (2005 $251 million and 2004 $147 million). |
| b | At 31 December 2006, the foreign currency translation reserve includes $122 million relating to non-current assets held for sale, which will be recycled to the income statement upon disposal of such assets. |
| c | Reclassification in respect of share repurchases in 2005. |
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| At 31 December 2004 | 5,403 | | 5,636 | | 730 | | 27,162 | |
| Adoption of IAS 39 | – | | – | | – | | – | |
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| At 1 January 2005 | 5,403 | | 5,636 | | 730 | | 27,162 | |
| Currency translation differences (net of tax) | – | | – | | – | | – | |
| Exchange gain on translation of foreign operations | | | | | | | | |
| transferred to (profit) or loss on sale (net of tax) | – | | – | | – | | – | |
| Actuarial gain relating to pensions and other post-retirement benefits (net of tax) | – | | – | | – | | – | |
| Issue of ordinary share capital for TNK-BP | 27 | | 1,223 | | – | | – | |
| Available-for-sale investments marked to market (net of tax) | – | | – | | – | | – | |
| Available-for-sale investments recycling (net of tax) | – | | – | | – | | – | |
| Repurchase of ordinary share capital | (265 | ) | – | | 19 | | – | |
| Share-based payments (net of tax) | 20 | | 512 | | – | | 28 | |
| Cash flow hedges marked to market (net of tax) | – | | – | | – | | – | |
| Cash flow hedges recycling (net of tax) | – | | – | | – | | – | |
| Profit for the year | – | | – | | – | | – | |
| Dividends | – | | – | | – | | – | |
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| At 31 December 2005 | 5,185 | | 7,371 | | 749 | | 27,190 | |
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| | capital | | account | | reserve | | reserve | |
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| At 1 January 2004 | 5,552 | | 3,957 | | 523 | | 27,077 | |
| Currency translation differences (net of tax) | – | | – | | – | | – | |
| Exchange gain on translation of foreign operations | | | | | | | | |
| transferred to (profit) or loss on sale (net of tax) | – | | – | | – | | – | |
| Actuarial gain relating to pensions and other post-retirement benefits (net of tax) | – | | – | | – | | – | |
| Unrealized gain on acquisition of further | | | | | | | | |
| investment in equity-accounted investments | – | | – | | – | | – | |
| Issue of ordinary share capital for TNK-BP | 35 | | 1,215 | | – | | – | |
| Repurchase of ordinary share capital | (207 | ) | – | | 207 | | – | |
| Share-based payments (net of tax) | 23 | | 464 | | – | | 85 | |
| Profit for the year | – | | – | | – | | – | |
| Dividends | – | | – | | – | | – | |
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| At 31 December 2004 | 5,403 | | 5,636 | | 730 | | 27,162 | |
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Back to Contents
| | | | | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | Foreign | | | | | | Share- | | | | | | | | | |
| | | | | | | currency | | Available- | | | | based | | Profit | | BP | | | | | |
| Other | | Own | | Treasury | | translation | | for-sale | | Cash flow | | payment | | and loss | | shareholders’ | | Minority | | Total | |
| reserve | | shares | a | shares | | reserve | b | investments | | hedges | | reserve | | account | | equity | | interest | | equity | |
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| 16 | | (140 | ) | (10,598 | ) | 2,943 | | 385 | | (234 | ) | 643 | | 46,151 | | 79,661 | | 789 | | 80,450 | |
| – | | (19 | ) | – | | 1,742 | | 27 | | 6 | | – | | – | | 1,756 | | 49 | | 1,805 | |
| – | | – | | – | | – | | – | | – | | – | | 1,795 | | 1,795 | | – | | 1,795 | |
| – | | – | | – | | – | | – | | – | | – | | – | | 1,250 | | – | | 1,250 | |
| – | | – | | – | | – | | 478 | | – | | – | | – | | 478 | | – | | 478 | |
| – | | – | | – | | – | | (504 | ) | – | | – | | – | | (504 | ) | – | | (504 | ) |
| – | | – | | (11,472 | ) | – | | – | | – | | – | | (4,009 | ) | (15,481 | ) | – | | (15,481 | ) |
| (11 | ) | 5 | | 134 | | – | | – | | – | | 216 | | (79 | ) | 773 | | – | | 773 | |
| – | | – | | – | | – | | – | | 313 | | – | | – | | 313 | | – | | 313 | |
| – | | – | | – | | – | | – | | (46 | ) | – | | – | | (46 | ) | – | | (46 | ) |
| – | | – | | – | | – | | – | | – | | – | | 22,315 | | 22,315 | | 286 | | 22,601 | |
| – | | – | | – | | – | | – | | – | | – | | (7,686 | ) | (7,686 | ) | (283 | ) | (7,969 | ) |
| – | | – | | (246 | ) | – | | – | | – | | – | | – | | – | | – | | – | |
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| 5 | | (154 | ) | (22,182 | ) | 4,685 | | 386 | | 39 | | 859 | | 58,487 | | 84,624 | | 841 | | 85,465 | |
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| | | | | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | Foreign | | | | | | Share- | | | | | | | | | |
| | | | | | | currency | | Available- | | | | based | | Profit | | BP | | | | | |
| Other | | Own | | Treasury | | translation | | for-sale | | Cash flow | | payment | | and loss | | shareholders’ | | Minority | | Total | |
| reserve | | shares | | shares | | reserve | | investments | | hedges | | reserve | | account | | equity | | interest | | equity | |
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| 44 | | (82 | ) | – | | 5,616 | | – | | – | | 443 | | 31,940 | | 76,892 | | 1,343 | | 78,235 | |
| – | | – | | – | | – | | 230 | | (118 | ) | – | | (355 | ) | (243 | ) | – | | (243 | ) |
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| 44 | | (82 | ) | – | | 5,616 | | 230 | | (118 | ) | 443 | | 31,585 | | 76,649 | | 1,343 | | 77,992 | |
| – | | 12 | | – | | (2,453 | ) | (35 | ) | (3 | ) | – | | – | | (2,479 | ) | (18 | ) | (2,497 | ) |
| – | | – | | – | | (220 | ) | – | | – | | – | | – | | (220 | ) | – | | (220 | ) |
| – | | – | | – | | – | | – | | – | | – | | 619 | | 619 | | – | | 619 | |
| – | | – | | – | | – | | – | | – | | – | | – | | 1,250 | | – | | 1,250 | |
| – | | – | | – | | – | | 232 | | – | | – | | – | | 232 | | – | | 232 | |
| – | | – | | – | | – | | (42 | ) | – | | – | | – | | (42 | ) | – | | (42 | ) |
| – | | – | | (10,601 | ) | – | | – | | – | | – | | (750 | ) | (11,597 | ) | – | | (11,597 | ) |
| (28 | ) | (70 | ) | 3 | | – | | – | | – | | 200 | | 30 | | 695 | | – | | 695 | |
| – | | – | | – | | – | | – | | (149 | ) | – | | – | | (149 | ) | – | | (149 | ) |
| – | | – | | – | | – | | – | | 36 | | – | | – | | 36 | | – | | 36 | |
| – | | – | | – | | – | | – | | – | | – | | 22,026 | | 22,026 | | 291 | | 22,317 | |
| – | | – | | – | | – | | – | | – | | – | | (7,359 | ) | (7,359 | ) | (827 | ) | (8,186 | ) |
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| 16 | | (140 | ) | (10,598 | ) | 2,943 | | 385 | | (234 | ) | 643 | | 46,151 | | 79,661 | | 789 | | 80,450 | |
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| | | | | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | Foreign | | | | | | Share- | | | | | | | | | |
| | | | | | | currency | | Available- | | | | based | | Profit | | BP | | | | | |
| Other | | Own | | Treasury | | translation | | for-sale | | Cash flow | | payment | | and loss | | shareholders’ | | Minority | | Total | |
| reserve | | shares | | shares | | reserve | | investments | | hedges | | reserve | | account | | equity | | interest | | equity | |
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| 129 | | (96 | ) | – | | 3,619 | | – | | – | | 212 | | 28,166 | | 69,139 | | 1,125 | | 70,264 | |
| – | | (7 | ) | – | | 2,075 | | – | | – | | – | | – | | 2,068 | | 64 | | 2,132 | |
| – | | – | | – | | (78 | ) | – | | – | | – | | – | | (78 | ) | – | | (78 | ) |
| – | | – | | – | | – | | – | | – | | – | | 203 | | 203 | | – | | 203 | |
| – | | – | | – | | – | | – | | – | | – | | 94 | | 94 | | – | | 94 | |
| – | | – | | – | | – | | – | | – | | – | | – | | 1,250 | | – | | 1,250 | |
| – | | – | | – | | – | | – | | – | | – | | (7,548 | ) | (7,548 | ) | – | | (7,548 | ) |
| (85 | ) | 21 | | – | | – | | – | | – | | 231 | | (9 | ) | 730 | | – | | 730 | |
| – | | – | | – | | – | | – | | – | | – | | 17,075 | | 17,075 | | 187 | | 17,262 | |
| – | | – | | – | | – | | – | | – | | – | | (6,041 | ) | (6,041 | ) | (33 | ) | (6,074 | ) |
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| 44 | | (82 | ) | – | | 5,616 | | – | | – | | 443 | | 31,940 | | 76,892 | | 1,343 | | 78,235 | |
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Back to Contents
43 Capital and reserves continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares.
Other reserve
The balance on the other reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares to be issued in the ARCO acquisition on the exercise of ARCO share options.
Own shares
Own shares represent BP shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based payment arrangements.
Treasury shares
Treasury shares represent BP shares repurchased and available for re-issue.
Foreign currency translation reserve
The foreign currency translation reserve is used to record exchange differences arising from the translations of the financial statements of foreign operations. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement. This reserve is also used to record the effect of hedging net investments in foreign operations.
Available-for-sale investments
This reserve records the changes in fair value on available-for-sale investments. On disposal, the cumulative changes in fair value are recycled to the income statement.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. When the hedged transaction occurs, the gain or loss on the hedging instrument is transferred out of equity to either profit or loss or the carrying value of assets, as appropriate. If the forecast transaction is no longer expected to occur the gain or loss recognized in equity is transferred to profit or loss.
Share-based payment reserve
This reserve represents cumulative amounts charged to profit in respect of employee share-based payment arrangements where the scheme has not yet been settled by means of an award of shares to an individual.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
Back to Contents
44 Share-based payments
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| Effect of share-based payment transactions on the group’s result and financial position | 2006 | | 2005 | | 2004 | |
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| Total expense recognized for equity-settled share-based payment transactions | 405 | | 348 | | 289 | |
| Total expense recognized for cash-settled share-based payment transactions | 14 | | 20 | | 36 | |
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| Total expense recognized for share-based payment transactions | 419 | | 368 | | 325 | |
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| Closing balance of liability for cash-settled share-based payment transactions | 38 | | 48 | | 59 | |
| Total intrinsic value for vested cash-settled share-based payments | 23 | | 41 | | 53 | |
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For ease of presentation, option and share holdings detailed in the tables within this note are stated as UK ordinary share equivalents in US dollars. US employees are granted American depositary shares (ADSs) or options over the company’s ADSs (one ADS is equivalent to six ordinary shares). The share-based payment plans that existed during the year are detailed below. All plans are ongoing unless otherwise stated.
Plans for executive directors
Executive Directors’ Incentive Plan (EDIP) – share element (2005 onwards)
An equity-settled incentive share plan for executive directors driven by one performance measure over a three-year performance period. The award of shares is determined by comparing BP’s total shareholder return (TSR) against the other oil majors. In addition, for the group chief executive, 27% of the grant is based on long-term leadership (LTL) measures. After the performance period, the shares which vest (net of tax) are then subject to a three-year retention period. The director’s remuneration report on pages 61-68 includes full details of this plan.
Executive Directors’ Incentive Plan (EDIP) – share element (pre-2005)
An equity-settled incentive share plan for executive directors driven by three performance measures over a three-year performance period. The primary measure is BP’s shareholder return against the market (SHRAM) versus that of the companies within the FTSE All World Oil & Gas Index. This accounts for nearly two-thirds of the potential total award, with the remainder being assessed on BP’s relative return on average capital employed (ROACE) and earnings per share (EPS) growth compared with the other oil majors. After the performance period, the shares that vest (net of tax) are then subject to a three-year retention period. The director’s remuneration report on pages 61-68 includes full details of this plan. For 2005 and subsequent years, the share element of EDIP was amended as described above.
Executive Directors’ Incentive Plan (EDIP) – share option element (pre-2005)
An equity-settled share option plan for executive directors that permits options to be granted at an exercise price no lower than the market price of a share on the date that the option is granted. Options vest over three years (one-third each after one, two and three years respectively) and must be exercised within seven years of the date of grant. Last grants were made in 2004. From 2005 onwards the remuneration committee’s policy is not to make further grants of share options to executive directors.
Plans for senior employees
Medium Term Performance Plan (MTPP) (2005 onwards)
An equity-settled incentive share plan for senior employees driven by two performance measures over a three-year performance period. The award of shares is determined by comparing BP’s TSR against the other oil majors and, additionally, by comparing free cash flow (FCF) against a threshold established for the period. For a small group of particularly senior employees, only the TSR measure is applicable in determining the award. The number of shares awarded is increased to take account of the net dividends that would have been received during the performance period, assuming that such dividends had been reinvested. With regard to leaver provisions, the general rule is that leaving employment during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion of the first year of the performance period.
Long Term Performance Plan (LTPP) (pre-2005)
An equity-settled incentive share plan for senior employees driven by three performance measures over a three-year performance period. The primary measure is BP’s SHRAM versus that of the companies within the FTSE All World Oil & Gas Index. This accounts for nearly two-thirds of the potential total award, with the remainder being assessed on BP’s relative ROACE and EPS growth compared with the other oil majors. Shares are awarded at the end of the performance period and are then subject to a three-year restriction period. With regard to leaver provisions, the general rule is that leaving during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion of the first year of the performance period. This plan was replaced by the MTPP for 2005 onwards.
Deferred Annual Bonus Plan (DAB)
An equity-settled restricted share plan for senior employees. The award value is equal to 50% of the annual cash bonus awarded for the preceding performance year (the ‘performance period’). The shares are restricted for a period of three years (the ‘restriction period’). Shares accrue dividends during the restriction period and these are reinvested. With regard to leaver provisions, if a participant ceases to be employed by BP prior to the end of the performance period, then the general rule is that this will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason. Similarly, if a participant ceases to be employed by BP prior to the end of the restriction period, the general rule is that the restricted shares will be forfeited. Special arrangements apply where the participant leaves for a qualifying reason.
Performance Share Plan (PSP)
An equity-settled restricted share plan for senior professionals and team leaders. The award takes into account the recipient’s performance in the prior calendar year (the ‘performance period’). Shares, provided initially as share units, are restricted for a period of three years (the ‘restriction period’). Share units accrue notional dividends during the restriction period and these are reinvested. At the end of the restriction period additional units may be awarded based on BP’s TSR performance against the other oil majors. At award, share units are converted into shares. With regard to leaver provisions, the general rule is that leaving during the performance period will preclude an award of share units. If a participant ceases to be employed by BP prior to the end of the restriction period, the general rule is that share units will lapse. Special arrangements apply where the participant leaves for a qualifying reason.
Back to Contents
44 Share-based payments continued
Restricted Share Plan (RSP)
An equity-settled restricted share plan used predominantly for senior employees in special circumstances (such as recruitment and retention). There are no performance conditions but the shares are subject to a three-year restriction period. During the restriction period, shares accrue dividends, which are reinvested. With regard to leaver provisions, the general rule is that ceasing employment during the restriction period will result in the forfeit of shares. However, special arrangements apply where the participant leaves for a qualifying reason.
BP Share Option Plan (BPSOP)
An equity-settled share option plan that applies to certain categories of employees. Participants are granted share options with an exercise price no lower than market price of a share immediately preceding the date of grant. There are no performance conditions and the options are exercisable between the third and 10th anniversaries of the grant date. The general rule is that the options will lapse if the participant leaves employment before the end of the third calendar year from the date of grant (and that vested options are exercisable within 3½ years from the date of leaving). However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after the end of the calendar year of the date of grant. From 2007, share options no longer form a regular element of our incentive plans.
Savings and matching plans
BP ShareSave Plan
A savings-related share option plan, under which employees save on a monthly basis, over a three- or five-year period, towards the purchase of shares at fixed price determined when the option is granted. This price is usually set at a 20% discount to the market price at the time of grant. The option must be exercised within six months of maturity of the savings contract; otherwise it lapses. The plan is run in the UK and options are granted annually, usually in June. Until 2003, a three-year savings plan was also run in a small number of other countries. Options will remain outstanding in respect of these countries until the end of June 2007. Participants leaving for a qualifying reason will have six months in which to use their savings to exercise their options on a pro-rated basis.
BP ShareMatch Plans
Matching share plans, under which BP matches employees’ own contributions of shares up to a predetermined limit. The plans are run in the UK and in over 70 other countries. The UK plan is run on a monthly basis with shares being held in trust for five years before they can be released free of any income tax and national insurance liability. In other countries, the plan is run on an annual basis with shares being held in trust for three years. The plan is operated on a cash basis in those countries where there are regulatory restrictions preventing the holding of BP shares. When the employee leaves BP, all shares must be removed from trust and units under the plan operated on a cash basis must be encashed.
Local plans
In some countries, BP provides local scheme benefits, the rules and qualifications for which vary according to local circumstances.
The above share plans are indicated as being equity-settled. However in certain countries it is not possible to award shares to employees owing to local legislation. In these instances the award will be settled in cash, calculated as the cash equivalent of the value to the employee of an equity-settled plan.
Cash plans
Cash Options / Stock Appreciation Rights (SARs)
These are cash-settled share-based payments available to certain employees that require the group to pay the intrinsic value of the cash option/SAR to the employee at the date of exercise. There are no performance conditions; however, participants must continue in employment with BP for the first three calendar years of the plan for the options/SARs to vest. Special arrangements may apply for qualifying leavers. The options/SARs are exercisable between the third and 10th anniversaries of the grant date.
Employee Share Ownership Plans (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards made to participants under EDIP, MTPP, LTPP, DAB and the BP ShareMatch Plans. The ESOPs have waived their rights to dividends on shares held for future awards and are funded by the group. Until such time as the company’s own shares held by the ESOP trusts vest unconditionally in employees, the amount paid for those shares is deducted in arriving at shareholders’ equity. See Note 43. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.
At 31 December 2006, the ESOPs held 12,795,887 shares (2005 14,560,003 shares and 2004 8,621,219 shares) for potential future awards, which had a market value of $142 million (2005 $156 million and 2004 $84 million).
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| Share option transactions | | | 2006 | | | | 2005 | | | | 2004 | |
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| | | | Weighted | | | | Weighted | | | | Weighted | |
| | Number | | average | | Number | | average | | Number | | average | |
| | of | | exercise price | | of | | exercise price | | of | | exercise price | |
| | options | | $ | | options | | $ | | options | | $ | |
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| Outstanding at beginning of the year | 450,453,502 | | 7.64 | | 470,263,808 | | 7.16 | | 461,885,881 | | 6.76 | |
| Granted during the year | 53,977,639 | | 11.18 | | 54,482,053 | | 10.24 | | 80,394,760 | | 7.93 | |
| Forfeited during the year | (7,169,710 | ) | 8.69 | | (4,844,827 | ) | 8.30 | | (7,043,911 | ) | 6.77 | |
| Exercised during the year | (70,658,480 | ) | 6.52 | | (68,687,976 | ) | 6.40 | | (62,625,182 | ) | 5.18 | |
| Expired during the year | (131,489 | ) | 7.99 | | (759,556 | ) | 6.75 | | (2,347,740 | ) | 7.55 | |
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| Outstanding at end of the year | 426,471,462 | | 8.25 | | 450,453,502 | | 7.64 | | 470,263,808 | | 7.16 | |
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| Exercisable at the end of the year | 236,726,966 | | 7.41 | | 222,729,398 | | 7.54 | | 224,627,758 | | 7.00 | |
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| Available for grant at 31 December | 699,535,945 | | | | 955,924,506 | | | | 966,076,636 | | | |
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Back to Contents
44 Share-based payments continued
As share options are exercised continuously throughout the year, the weighted average share price during the year of $11.85 (2005 $10.77 and 2004 $8.95) is representative of the weighted average share price at the date of exercise. For the options outstanding at 31 December 2006, the exercise price ranges and weighted average remaining contractual lives are shown below.
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| | | | Options outstanding | | Options exercisable | |
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| | | | Weighted | | Weighted | | | | Weighted | |
| | Number | | average | | average | | Number | | average | |
| | of | | remaining life | | exercise price | | of | | exercise price | |
| Range of exercise prices | shares | | Years | | $ | | shares | | $ | |
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| $5.10 – $6.79 | 100,854,491 | | 3.92 | | 6.02 | | 87,474,704 | | 6.06 | |
| $6.80 – $8.50 | 196,009,067 | | 4.93 | | 8.01 | | 122,344,799 | | 8.08 | |
| $8.51 – $10.21 | 55,376,829 | | 5.79 | | 9.30 | | 26,907,463 | | 8.76 | |
| $10.22 – $11.92 | 74,231,075 | | 8.81 | | 11.14 | | – | | – | |
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| | 426,471,462 | | 5.48 | | 8.25 | | 236,726,966 | | 7.41 | |
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| Fair values and associated details for options and shares granted | | | | | |
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| Options granted in 2006 | BPSOP | | ShareSave 3 year | | ShareSave 5 year | |
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| Option pricing model used | Binomial | | Binomial | | Binomial | |
| Weighted average fair value | $2.46 | | $2.88 | | $3.08 | |
| Weighted average share price | $11.07 | | $11.08 | | $11.08 | |
| Weighted average exercise price | $11.17 | | $9.10 | | $9.10 | |
| Expected volatility | 22% | | 24% | | 24% | |
| Option life | 10 years | | 3.5 years | | 5.5 years | |
| Expected dividends | 3.23% | | 3.40% | | 3.40% | |
| Risk free interest rate | 4.50% | | 5.00% | | 4.75% | |
| Expected exercise behaviour | 5% years 4-9, | | 100% year 4 | | 100% year 6 | |
| | 70% year 10 | | | | | |
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| Options granted in 2005 | BPSOP | | ShareSave 3 year | | ShareSave 5 year | |
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| Option pricing model used | Binomial | | Binomial | | Binomial | |
| Weighted average fair value | $2.34 | | $2.76 | | $2.94 | |
| Weighted average share price | $10.85 | | $10.49 | | $10.49 | |
| Weighted average exercise price | $10.63 | | $7.96 | | $7.96 | |
| Expected volatility | 18% | | 18% | | 18% | |
| Option life | 10 years | | 3.5 years | | 5.5 years | |
| Expected dividends | 2.72% | | 3.00% | | 3.00% | |
| Risk free interest rate | 4.25% | | 4.00% | | 4.25% | |
| Expected exercise behaviour | 5% years 4-9, | | 100% year 4 | | 100% year 6 | |
| | 70% year 10 | | | | | |
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| Options granted in 2004 | EDIP Options | | BPSOP | | ShareSave 3 year | | ShareSave 5 year | |
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| Option pricing model used | Binomial | | Binomial | | Binomial | | Binomial | |
| Weighted average fair value | $1.34 | | $1.55 | | $1.94 | | $2.13 | |
| Weighted average share price | $8.09 | | $8.12 | | $8.75 | | $8.75 | |
| Weighted average exercise price | $8.09 | | $8.09 | | $7.00 | | $7.00 | |
| Expected volatility | 22% | | 22% | | 22% | | 22% | |
| Option life | 7 years | | 10 years | | 3.5 years | | 5.5 years | |
| Expected dividends | 3.75% | | 3.75% | | 3.75% | | 3.75% | |
| Risk free interest rate | 3.50% | | 4.00% | | 3.00% | | 3.75% | |
| Expected exercise behaviour | 5% years 2-6, | | 5% years 4-9, | | 100% year 4 | | 100% year 6 | |
| | 75% year 7 | | 70% year 10 | | | | | |
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The group uses a third party estimate of expected volatility of US ADSs for the quarter within which the grant date of the relevant plan falls. This estimate takes into account the volatility implied by options in the market.
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| | MTPP- | | MTPP- | | EDIP- | | EDIP- | | | |
| Shares granted in 2006 | TSR | | FCF | | TSR | | LTL | | RSP | |
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| Number of equity instruments granted (million) | 8.7 | | 7.8 | | 3.3 | | 0.5 | | 0.5 | |
| Weighted average fair value | $7.28 | | $11.23 | | $4.87 | | $11.23 | | $11.07 | |
| Fair value measurement basis | Monte Carlo | | Market value | | Monte Carlo | | Market value | | Market value | |
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| | MTPP - | | MTPP - | | EDIP - | | EDIP - | | | |
| Shares granted in 2005 | TSR | | FCF | | TSR | | LTL | | RSP | |
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| Number of equity instruments granted (million) | 9.3 | | 8.4 | | 3.7 | | 0.5 | | 0.3 | |
| Weighted average fair value | $5.72 | | $11.04 | | $3.87 | | $10.13 | | $11.04 | |
| Fair value measurement basis | Monte Carlo | | Market value | | Monte Carlo | | Market value | | Market value | |
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Back to Contents
44 Share-based payments continued
The group used a Monte Carlo simulation to fair value the TSR element of the 2006 and 2005 MTPP and EDIP plans. In accordance with the rules of the plans the model simulates BP’s TSR and compares it against our principal strategic competitors over the three-year period of the plans. The model takes into account the historic dividends, share price volatilities and covariances of BP and each comparator company to produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the TSR element.
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| | LTPP- | | LTPP- | | EDIP- | | EDIP- | | | |
| Shares granted in 2004 | SHRAM | | EPS/ROACE | | SHRAM | | EPS/ROACE | | RSP | |
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| Number of equity instruments granted (million) | 6.8 | | 4.1 | | 0.9 | | 0.5 | | 0.1 | |
| Weighted average fair value | $4.06 | | $7.21 | | $4.06 | | $7.21 | | $8.12 | |
| Fair value measurement basis | Monte Carlo | | Market value | | Monte Carlo | | Market value | | Market value | |
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The group used a Monte Carlo simulation to fair value the SHRAM element of the 2004 LTPP and EDIP plan. In accordance with the rules of the plan, the model simulates BP’s SHRAM and compares it with the comparator companies (all companies in the FTSE All World Oil & Gas Index) over the three-year period of the plan. The SHRAMs of the comparator companies have been determined from market data over the preceding three-year period. The model takes into account the historic dividend yields, share price volatilities and covariances of BP and each comparator company to produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the SHRAM element.
Accounting expense does not necessarily represent the actual value of share-based payments made to recipients which are determined by the Remuneration Committee according to established criteria.
45 Employee costs and numbers
| | | | | | $ million | |
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| Employee costs | 2006 | | 2005 | | 2004 | |
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| Wages and salaries | 8,411 | | 8,695 | | 7,922 | |
| Social security costs | 751 | | 754 | | 667 | |
| Share-based payments | 419 | | 368 | | 325 | |
| Pension and other post-retirement benefit costs | 770 | | 929 | | 1,051 | |
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| | 10,351 | | 10,746 | | 9,965 | |
| Innovene operations | – | | (892 | ) | (898 | ) |
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| Continuing operations | 10,351 | | 9,854 | | 9,067 | |
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| Number of employees at 31 December | 2006 | | 2005 | | 2004 | |
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| Exploration and Production | 19,000 | | 17,000 | | 15,600 | |
| Refining and Marketinga | 69,500 | | 70,800 | | 69,800 | |
| Gas, Power and Renewables | 4,500 | | 4,100 | | 4,000 | |
| Other businesses and corporate | 4,000 | | 4,300 | | 13,500 | |
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| | 97,000 | | 96,200 | | 102,900 | |
| By geographical area | | | | | | |
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| UK | 16,900 | | 16,500 | | 17,500 | |
| Rest of Europe | 20,200 | | 21,300 | | 25,900 | |
| USA | 33,700 | | 34,400 | | 36,900 | |
| Rest of World | 26,200 | | 24,000 | | 22,600 | |
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| | 97,000 | | 96,200 | | 102,900 | |
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| a | Includes 26,100 (2005 27,800 and 2004 27,900) service station staff. |
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| | 2006 | | 2005 | |
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| | | | Rest of | | | | Rest of | | | | | | Rest of | | | | Rest of | | | |
| Average number of employees | UK | | Europe | | USA | | World | | Total | | UK | | Europe | | USA | | World | | Total | |
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| Exploration and Production | 3,300 | | 700 | | 6,100 | | 8,100 | | 18,200 | | 3,000 | | 600 | | 5,300 | | 7,300 | | 16,200 | |
| Refining and Marketing | 11,300 | | 19,300 | | 24,900 | | 15,000 | | 70,500 | | 11,100 | | 19,700 | | 26,200 | | 14,000 | | 71,000 | |
| Gas, Power and Renewables | 300 | | 700 | | 1,600 | | 1,700 | | 4,300 | | 200 | | 800 | | 1,500 | | 1,400 | | 3,900 | |
| Other businesses and corporate | 1,900 | | 200 | | 1,900 | | 100 | | 4,100 | | 3,800 | | 3,900 | | 3,600 | | 300 | | 11,600 | |
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| | 16,800 | | 20,900 | | 34,500 | | 24,900 | | 97,100 | | 18,100 | | 25,000 | | 36,600 | | 23,000 | | 102,700 | |
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| | | | Rest of | | | | Rest of | | | |
| Average number of employees | UK | | Europe | | USA | | World | | Total | |
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| Exploration and Production | 2,900 | | 700 | | 4,900 | | 6,900 | | 15,400 | |
| Refining and Marketing | 10,300 | | 19,200 | | 27,200 | | 12,900 | | 69,600 | |
| Gas, Power and Renewables | 200 | | 800 | | 1,400 | | 1,600 | | 4,000 | |
| Other businesses and corporate | 3,700 | | 4,800 | | 5,700 | | 1,000 | | 15,200 | |
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| | 17,100 | | 25,500 | | 39,200 | | 22,400 | | 104,200 | |
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Back to Contents
46 Remuneration of directors and key management
| Remuneration of directors | | | | | $ million | |
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| Total for all directors | | | | | | |
| Emoluments | 14 | | 18 | | 19 | |
| Gains made on the exercise of share options | 12 | | – | | 3 | |
| Amounts awarded under incentive schemes | 14 | | 8 | | 6 | |
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Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus bonuses awarded for the year.
Pension contributions
Five executive directors participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which contributions are made by BP based on actuarial advice. One US executive director participated in the US BP Retirement Accumulation Plan during 2006.
Office facilities for former chairmen and deputy chairmen
It is customary for the company to make available to former chairmen and deputy chairmen, who were previously employed executives, the use of office and basic secretarial facilities following their retirement. The cost involved in doing so is not significant.
Further information
Full details of individual directors’ remuneration are given in the directors’ remuneration report on pages 61-68.
| Remuneration of key management | | | | | $ million | |
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| Total for all key management | | | | | | |
| Short-term employee benefits | 30 | | 25 | | 24 | |
| Post-retirement benefits | 4 | | 4 | | 3 | |
| Share-based payments | 26 | | 27 | | 20 | |
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Key management, in addition to executive and non-executive directors, includes other senior managers who attend the Group Chief Executive’s Meeting.
Short-term employee benefits
In addition to fees paid to the non-executive chairman and non-executive directors, these amounts comprise, for executive directors and senior managers, salary and benefits earned during the year, plus bonuses awarded for the year.
Post-retirement benefits
The amounts represent the estimated cost to the group of providing defined benefit pensions and other post-retirement benefits to key management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of key management’s participation in share-based payment plans, as measured by the fair value of options and shares granted accounted for in accordance with IFRS 2 ‘Share-based Payments’. The main plans in which key management have participated are the Executive Directors’ Incentive Plan (EDIP), the Medium Term Performance Plan (MTPP) and the Long Term Performance Plan (LTPP). For details of these plans refer to Note 44.
Back to Contents
47 Contingent liabilities
There were contingent liabilities at 31 December 2006 in respect of guarantees and indemnities entered into as part of the ordinary course of the group’s business. No material losses are likely to arise from such contingent liabilities. Group companies have issued guarantees under which amounts outstanding at 31 December 2006 were $1,123 million (2005 $1,228 million) in respect of borrowings of jointly controlled entities and associates and $789 million (2005 $736 million) in respect of liabilities of other third parties.
Approximately 200 lawsuits were filed in State and Federal Courts in Alaska seeking compensatory and punitive damages arising out of the Exxon Valdez oil spill in Prince William Sound in March 1989. Most of those suits named Exxon (now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies that own Alyeska. Alyeska initially responded to the spill until the response was taken over by Exxon. BP owns a 47% interest (reduced during 2001 from 50% by a sale of 3% to Phillips) in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP’s combination with Atlantic Richfield Company (Atlantic Richfield). Alyeska and its owners have settled all the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages which it has incurred. If any claims are asserted by Exxon that affect Alyeska and its owners, BP will defend the claims vigorously.
Since 1987, Atlantic Richfield, a current subsidiary of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed as against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting & Refining which, along with a predecessor company, manufactured lead pigment during the period 1920-1946. Plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits (depending on plaintiff) seek various remedies, including: compensation to lead-poisoned children; cost to find and remove lead paint from buildings; medical monitoring and screening programmes; public warning and education on lead hazards; reimbursement of government healthcare costs and special education for lead-poisoned citizens; and punitive damages. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences and it intends to defend such actions vigorously and thus the incurrence of a liability by Atlantic Richfield is remote. Consequently, BP believes that the impact of these lawsuits on the group’s results of operations, financial position or liquidity will not be material.
In addition, various group companies are parties to legal actions and claims that arise in the ordinary course of the group’s business. While the outcome of such legal proceedings cannot be readily foreseen, BP believes that they will be resolved without material effect on the group’s results of operations, financial position or liquidity.
The group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations has been provided in these accounts in accordance with the group’s accounting policies. While the amounts of future costs could be significant and could be material to the group’s results of operations in the period in which they are recognized, BP does not expect these costs to have a material effect on the group’s financial position or liquidity.
The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the group. Losses will therefore be borne as they arise rather than being spread over time through insurance premiums with attendant transaction costs. The position is reviewed periodically.
48 Capital commitments
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been placed at 31 December 2006 amounted to $9,773 million (2005 $7,596 million). Capital commitments of jointly controlled entities amounted to $1,217 million (2005 $576 million).
49 First-time adoption of International Financial Reporting Standards
| | For all periods up to and including the year ended 31 December 2004, BP prepared its financial statements in accordance with UK generally accepted accounting practice (UK GAAP). BP, together with all other European Union (EU) companies listed on an EU stock exchange, was required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU with effect from 1 January 2005. The Annual Report and Accounts for the year ended 31 December 2005 comprised BP’s first consolidated financial statements prepared under IFRS. |
| | The general principle for first-time adoption of IFRS is that standards in force at the first reporting date (for BP, 31 December 2005) are applied retrospectively. However, IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’ contains a number of exemptions that companies are permitted to apply. BP elected to take advantage of the exemption allowing comparative information on financial instruments to be prepared in accordance with UK GAAP and the group adopted IAS 32 ‘Financial Instruments: Disclosure and Presentation’ (IAS 32) and IAS 39 ‘Financial Instruments: Recognition and Measurement’ (IAS 39) from 1 January 2005. |
| | Had IAS 32 and IAS 39 been applied from 1 January 2003, BP’s date of transition for all other IFRS in force at the first reporting date, the following are the most significant adjustments that would have been necessary in the financial statements for the year ended 31 December 2004: |
| | – | All derivatives, including embedded derivatives, would have been brought on to the balance sheet at fair value, and changes in fair value would have been recognized in the income statement. |
| | – | Available-for-sale investments would have been carried at fair value rather than at cost and changes in fair value would have been recognized directly in equity. |
Back to Contents
49 First-time adoption of International Financial Reporting Standards continued
The reconciliation set out below shows the adjustments to the group balance sheet at 1 January 2005 on the adoption of IAS 32 and IAS 39.
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| Group balance sheet reconcilation | | $ million | |
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| | | | | | | | | | Other | | Other | | | | | | | | | | | |
| | | | | | | | | | non- | | non- | | | | | | Elimination | | | | | |
| | | | | | | | Non- | | financial | | financial | | Available- | | | | of | | | | | |
| | IFRS at | | | | | | qualifying | | contracts | | contracts | | for-sale | | | | deferred | | Total | | IFRS at | |
| | 31 December | | Fair value | | Cash flow | | hedge | | at fair | | no longer | | financial | | Embedded | | gains/ | | IAS 39 | | 1 January | |
| | 2004 | | hedges | | hedges | | derivatives | | value | | at fair value | | assets | | derivatives | | losses | | adjustments | | 2005 | |
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| Non-current assets | | | | | | | | | | | | | | | | | | | | | | |
| Property, plant and equipment | 93,092 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 93,092 | |
| Goodwill | 10,857 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 10,857 | |
| Intangible assets | 4,205 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 4,205 | |
| Investments in jointly controlled entities | 14,556 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 14,556 | |
| Investments in associates | 5,486 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 5,486 | |
| Other investments | 394 | | – | | – | | – | | – | | – | | 344 | | – | | – | | 344 | | 738 | |
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| Fixed assets | 128,590 | | – | | – | | – | | – | | – | | 344 | | – | | – | | 344 | | 128,934 | |
| Loans | 811 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 811 | |
| Other receivables | 429 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 429 | |
| Derivative financial instruments | 898 | | 112 | | 79 | | 8 | | 110 | | (34 | ) | – | | 599 | | (147 | ) | 727 | | 1,625 | |
| Prepayments and accrued income | 354 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 354 | |
| Defined benefit pension plan surplus | 2,105 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 2,105 | |
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| | 133,187 | | 112 | | 79 | | 8 | | 110 | | (34 | ) | 344 | | 599 | | (147 | ) | 1,071 | | 134,258 | |
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| Current assets | | | | | | | | | | | | | | | | | | | | | | |
| Loans | 193 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 193 | |
| Inventories | 15,645 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 15,645 | |
| Trade and other receivables | 37,099 | | – | | (2 | ) | – | | – | | – | | – | | – | | – | | (2 | ) | 37,097 | |
| Derivative financial instruments | 5,317 | | – | | 141 | | 178 | | 34 | | 47 | | – | | 278 | | – | | 678 | | 5,995 | |
| Prepayments and accrued income | 1,671 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 1,671 | |
| Current tax receivable | 159 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 159 | |
| Cash and cash equivalents | 1,359 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 1,359 | |
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| | 61,443 | | – | | 139 | | 178 | | 34 | | 47 | | – | | 278 | | – | | 676 | | 62,119 | |
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| Total assets | 194,630 | | 112 | | 218 | | 186 | | 144 | | 13 | | 344 | | 877 | | (147 | ) | 1,747 | | 196,377 | |
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| Current liabilities | | | | | | | | | | | | | | | | | | | | | | |
| Trade and other payables | 38,540 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 38,540 | |
| Derivative financial instruments | 5,074 | | – | | 16 | | 210 | | 14 | | – | | – | | 402 | | – | | 642 | | 5,716 | |
| Accruals and deferred income | 4,482 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 4,482 | |
| Finance debt | 10,184 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 10,184 | |
| Current tax payable | 4,131 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 4,131 | |
| Provisions | 715 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 715 | |
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| | 63,126 | | – | | 16 | | 210 | | 14 | | – | | – | | 402 | | – | | 642 | | 63,768 | |
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| Non-current liabilities | | | | | | | | | | | | | | | | | | | | | | |
| Other payables | 3,581 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 3,581 | |
| Derivative financial instruments | 158 | | 129 | | 4 | | 17 | | 12 | | – | | – | | 1,151 | | – | | 1,313 | | 1,471 | |
| Accruals and deferred income | 699 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 699 | |
| Finance debt | 12,907 | | (17 | ) | – | | – | | – | | – | | – | | – | | 164 | | 147 | | 13,054 | |
| Deferred tax liabilities | 16,701 | | – | | 60 | | (13 | ) | 44 | | 5 | | 114 | | (267 | ) | (55 | ) | (112 | ) | 16,589 | |
| Provisions | 8,884 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 8,884 | |
| Defined benefit pension plan and otherpost-retirement benefit plan deficits | 10,339 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 10,339 | |
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| | 53,269 | | 112 | | 64 | | 4 | | 56 | | 5 | | 114 | | 884 | | 109 | | 1,348 | | 54,617 | |
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| Total liabilities | 116,395 | | 112 | | 80 | | 214 | | 70 | | 5 | | 114 | | 1,286 | | 109 | | 1,990 | | 118,385 | |
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| Net assets | 78,235 | | – | | 138 | | (28 | ) | 74 | | 8 | | 230 | | (409 | ) | (256 | ) | (243 | ) | 77,992 | |
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| BP shareholders’ equity | 76,892 | | – | | 138 | | (28 | ) | 74 | | 8 | | 230 | | (409 | ) | (256 | ) | (243 | ) | 76,649 | |
| Minority interest | 1,343 | | – | | – | | – | | – | | – | | – | | – | | – | | – | | 1,343 | |
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| Total equity | 78,235 | | – | | 138 | | (28 | ) | 74 | | 8 | | 230 | | (409 | ) | (256 | ) | (243 | ) | 77,992 | |
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The fair values of embedded derivatives are included within non-current and current derivative financial instruments on the group balance sheet as this is believed to be the most appropriate presentation. Previously, these balances were reported within non-current and current prepayments and accrued income and accruals and deferred income.
Back to Contents
49 First-time adoption of International Financial Reporting Standards continued
Adjustments required to the balance sheet as at 1 January 2005 for the adoption of IAS 32 and IAS 39
Under UK GAAP, all derivatives used for trading purposes were recognized on the balance sheet at fair value. However, derivative financial instruments used for hedging purposes were recognized by applying either the accrual method or the deferral method. Under the accrual method, which was used for derivatives, principally swaps, used to manage interest rate risk, amounts payable or receivable in respect of derivatives are recognized ratably in earnings over the period of the contracts. Changes in the derivative’s fair value are not recognized. Under the deferral method, gains and losses from derivatives were deferred and recognized in earnings or as adjustments to carrying amounts as the underlying hedged transaction matured or occurred. This method was applied for derivatives used to convert non-US dollar borrowings into US dollars, to hedge significant non-US dollar firm commitments or anticipated transactions, and to manage some of the group’s exposure to natural gas and power price fluctuations.
For IFRS, all financial assets and financial liabilities are recognized initially at fair value. In subsequent periods the measurement of these financial instruments depends on their classification into one of the following measurement categories: i) financial assets or financial liabilities at-fair-value-through-profit-and-loss (such as those used for trading purposes and all derivatives which do not qualify for hedge accounting); ii) loans and receivables; and iii) available-for-sale financial assets (including certain investments held for the long term).
Fair value hedges
Where fair value hedge accounting was applied to transactions that hedge the group’s exposure to the changes in the fair value of a firm commitment or a recognized asset or liability that are attributable to a specific risk the derivatives designated as hedging instruments are recorded at their fair value in the group’s balance sheet and changes in their fair value are recognized in the income statement. Any gain or loss on the hedged item attributable to the hedged risk is adjusted against the carrying amount of the hedged item and recognized in the income statement.
The ‘pay floating’ interest rate swaps and currency swaps hedging the debt book in place on 1 January 2005 were highly effective and consequently qualify as fair value hedges for hedge accounting. The full fair value of the swaps was recognized on the balance sheet and the carrying value of debt was adjusted.
Cash flow hedges
The group uses currency derivatives to hedge its exposure to variability in cash flows arising either from a recognized asset or liability or a forecast transaction. The hedged instrument is recognized at fair value on the balance sheet. At maturity of the hedged item, the element deferred in equity is treated in accordance with the nature of the hedged exposure, for example, capitalized into the cost of an item of property, plant and equipment, or expensed in the case of a hedge of a tax payment.
Non-qualifying hedge derivatives
Under IAS 39, there are strict criteria that need to be met in order for hedge accounting to be applied. This adjustment records the impact of those derivatives, or elements thereof, held by the group that do not qualify for hedge accounting, or hedges for which hedge accounting has not been claimed under IAS 39. From 1 January 2005, these positions will be fair valued (‘marked to market’) and the change in fair value taken to income.
Other non-financial contracts at fair value
Certain net-settled non-financial contracts are deemed to meet the definition of financial instruments under IAS 39 and, as such, need to be recorded on the balance sheet at fair value.
Other non-financial contracts no longer at fair value
Certain non-financial contracts held for trading purposes were marked to market under UK GAAP. However, under IFRS they could no longer be recorded at fair value as they did not meet the definition of financial assets or financial liabilities. These contracts are accounted for on an accruals basis.
Available-for-sale financial assets
Under UK GAAP, the group’s investments other than subsidiaries, jointly controlled entities and associates were stated at cost less accumulated impairment losses.
For IFRS, these investments are classified as available-for-sale financial assets, and are recorded at fair value with the gain or loss arising as a result of the change in fair value being recorded directly in equity.
The transition adjustment relates to the fair value of listed investments held by the group. In accordance with IAS 39, all future fair value adjustments will be booked directly in equity until disposal of the investment, when the cumulative associated gains or losses are recycled through the income statement. At this point, the gain or loss on disposal under IFRS will be identical to that which would result using historical cost accounting.
Embedded derivatives
Embedded derivatives are required to be separated from their host contracts and separately recorded at fair value, with any resulting change in gain or loss in the period being recognized in the income statement.
Certain contracts have been determined to contain embedded derivatives. These embedded derivatives will be fair valued at each period end with the resulting gains or losses taken to the income statement.
Elimination of currently deferred gains and losses from derivatives
Under UK GAAP, gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. Where derivatives that are used to manage interest rate risk, to convert non-US dollar debtor to hedge other anticipated cash flows are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying debt or hedged transaction.
On transition to IFRS, only assets and liabilities that qualify as such can continue to be recognized. Consequently, all gains and losses that were generated by derivatives used for hedging purposes and deferred in the balance sheet as if they were assets or liabilities must be eliminated from the transitional balance sheet. This is achieved by transferring gains and losses arising from cash flow hedges to equity, pending recycling to income at a later date, and by transferring gains and losses arising from fair value hedges to adjust the carrying value of the hedged item, in this case, finance debt.
Back to Contents
50 Subsidiaries, jointly controlled entities and associates
The more important subsidiaries, jointly controlled entities and associates of the group at 31 December 2006 and the group percentage of ordinary share capital or joint venture interest (to nearest whole number) are set out below. The principal country of operation is generally indicated by the company’s country of incorporation or by its name. Those held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of investments in subsidiaries, jointly controlled entities and associates will be attached to the parent company’s annual return made to the Registrar of Companies.
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| | | | Country of | | | | | | | | Country of | | |
| Subsidiaries | % | | incorporation | | Principal activities | | Subsidiaries | | % | | incorporation | | Principal activities |
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| International | | | | | | | Netherlands | | | | | | |
| BP Chemicals | | | | | | | BP Capital | | 100 | | Netherlands | | Finance |
| Investments | 100 | | England | | Petrochemicals | | BP Nederland | | 100 | | Netherlands | | Refining and marketing |
| BP Exploration Op. Co. | 100 | | England | | Exploration and production | | | | | | | | |
| *BP Global Investments | 100 | | England | | Investment holding | | New Zealand | | | | | | |
| *BP International | 100 | | England | | Integrated oil operations | | BP Oil New Zealand | | 100 | | New Zealand | | Marketing |
| BP Oil International | 100 | | England | | Integrated oil operations | | | | | | | | |
| *BP Shipping | 100 | | England | | Shipping | | Norway | | | | | | |
| *Burmah Castrol | 100 | | Scotland | | Lubricants | | BP Norge | | 100 | | Norway | | Exploration and production |
| Algeria | | | | | | | Spain | | | | | | |
| BP Amoco Exploration | | | | | | | BP España | | 100 | | Spain | | Refining and marketing |
| (In Amenas) | 100 | | Scotland | | Exploration and production | | | | | | | | |
| BP Exploration (El | | | | | | | South Africa | | | | | | |
| Djazair) | 100 | | Bahamas | | Exploration and production | | *BP Southern Africa | | 75 | | South Africa | | Refining and marketing |
| Angola | | | | | | | Trinidad & Tobago | | | | | | |
| BP Exploration (Angola) | 100 | | England | | Exploration and production | | BP Trinidad (LNG) | | 100 | | Netherlands | | Exploration and production |
| | | | | | | | BP Trinidad and Tobago | | 70 | | US | | Exploration and production |
| Australia | | | | | | | | | | | | | |
| BP Oil Australia | 100 | | Australia | | Integrated oil operations | | UK | | | | | | |
| BP Australia Capital | | | | | | | BP Capital Markets | | 100 | | England | | Finance |
| Markets | 100 | | Australia | | Finance | | BP Chemicals | | 100 | | England | | Petrochemicals |
| BP Developments | | | | | | | BP Oil UK | | 100 | | England | | Refining and marketing |
| Australia | 100 | | Australia | | Exploration and production | | Britoil | | 100 | | Scotland | | Exploration and production |
| BP Finance Australia | 100 | | Australia | | Finance | | Jupiter Insurance | | 100 | | Guernsey | | Insurance |
| | | | | | | | | | | | | | |
| Azerbaijan | | | | | | | US | | | | | | |
| Amoco Caspian Sea | | | British Virgin | | Exploration and production | | Atlantic Richfield Co. |  | | | |  | |
| Petroleum | 100 | | Islands | | | | *BP America | | | | |
| BP Exploration | | | | | | | BP America | | | | |
| (Caspian Sea) | 100 | | England | | Exploration and production | | Production Company | | | | |
| | | | | | | | BP Amoco Chemical | | | | |
| Canada | | | | | | | Company | | | | Exploration and production, |
| BP Canada Energy | 100 | | Canada | | Exploration and production | | BP Company | | | | gas, power and |
| BP Canada Finance | 100 | | Canada | | Finance | | North America | | | | renewables, |
| | | | | | | | BP Corporation | 100 | | US | refining and marketing, |
| | | | | | | | North America | | | | pipelines and |
| Egypt | | | | | | | BP Exploration Alaska | | | | petrochemicals |
| BP Egypt Co. | 100 | | US | | Exploration and production | | Inc. | | | | |
| BP Egypt Gas Co. | 100 | | US | | Exploration and production | | BP Products | | | | |
| | | | | | | | North America | | | | |
| France | | | | | | | BP West Coast | | | | |
| BP France | 100 | | France | | Refining and marketing | | Products | | | | |
| | | | | | and petrochemicals | | Standard Oil Co. | | | | |
| Germany | | | | | | | BP Capital Markets | | | | Finance |
| Deutsche BP | 100 | | Germany | | Refining and marketing | | America | | | | |
| | | | | | and petrochemicals | | | | | | |
Back to Contents
50 Subsidiaries, jointly controlled entities and associates continued
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| | | Country of incorporation | | |
| Jointly controlled entities | % | | or registration | | Principal activities |
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| Atlantic 4 Holdings | 38 | | US | | LNG manufacture |
| Atlantic LNG 2/3 Company of Trinidad and Tobago | 43 | | Trinidad & Tobago | | LNG manufacture |
| LukArco | 46 | | Netherlands | | Exploration and production, pipelines |
| Pan American Energya | 60 | | US | | Exploration and production |
| Ruhr Oel | 50 | | Germany | | Refining and marketing and petrochemicals |
| Shanghai SECCO Petrochemical Co. | 50 | | China | | Petrochemicals |
| TNK-BP | 50 | | British Virgin Islands | | Integrated oil operations |
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| a | Pan American Energy is not controlled by BP, as certain key business decisions require joint approval of both BP and the minority partner. It is thus classified as a jointly controlled entity rather than a subsidiary. |
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| Associates | % | | Country of incorporation | | Principal activities |
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| Abu Dhabi | | | | | |
| Abu Dhabi Marine Areas | 37 | | England | | Crude oil production |
| Abu Dhabi Petroleum Co. | 24 | | England | | Crude oil production |
| Azerbaijan | | | | | |
| The Baku-Tbilisi-Ceyhan Pipeline Co. | 30 | | Cayman Islands | | Pipelines |
| South Caucasus Pipeline Co. | 26 | | Cayman Islands | | Pipelines |
| Trinidad & Tobago | | | | | |
| Atlantic LNG Company of Trinidad and Tobago | 34 | | Trinidad & Tobago | | LNG manufacture |
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Back to Contents
51 Oil and natural gas exploration and production activitiesa
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2006 | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Capitalized costs at 31 December | | | | | | | | | | | | | | | | | | |
| Gross capitalized costs | | | | | | | | | | | | | | | | | | |
| Proved properties | 32,528 | | 4,951 | | 44,856 | | 9,404 | | 3,569 | | 15,516 | | – | | 6,278 | | 117,102 | |
| Unproved properties | 423 | | 116 | | 1,443 | | 379 | | 1,155 | | 936 | | 1 | | 137 | | 4,590 | |
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| | 32,951 | | 5,067 | | 46,299 | | 9,783 | | 4,724 | | 16,452 | | 1 | | 6,415 | | 121,692 | |
| Accumulated depreciation | 22,908 | | 3,175 | | 19,724 | | 4,618 | | 1,709 | | 6,944 | | – | | 1,708 | | 60,786 | |
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| Net capitalized costs | 10,043 | | 1,892 | | 26,575 | | 5,165 | | 3,015 | | 9,508 | | 1 | | 4,707 | | 60,906 | |
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The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2006 was $10,870 million.
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| Costs incurred for the year ended 31 December | | | | | | | | | | | | | | | | | |
| Acquisition of properties | | | | | | | | | | | | | | | | | | |
| Proved | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Unproved | – | | – | | 74 | | 8 | | 2 | | 70 | | – | | – | | 154 | |
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| | – | | – | | 74 | | 8 | | 2 | | 70 | | – | | – | | 154 | |
| Exploration and appraisal costsb | 132 | | 26 | | 838 | | 135 | | 45 | | 434 | | 73 | | 82 | | 1,765 | |
| Development costs | 794 | | 214 | | 3,579 | | 820 | | 238 | | 2,356 | | – | | 1,108 | | 9,109 | |
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| Total costs | 926 | | 240 | | 4,491 | | 963 | | 285 | | 2,860 | | 73 | | 1,190 | | 11,028 | |
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The group’s share of jointly controlled entities’ and associates’ costs incurred in 2006 was $1,688 million: in Russia $1,109 milion, Rest of Americas $424 million, Asia Pacific $16 million and other $139 million.
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| Results of operations for the year | | | | | | | | | | | | | | | | | | |
| ended 31 December | | | | | | | | | | | | | | | | | | |
| Sales and other operating revenuesc | | | | | | | | | | | | | | | | | | |
| Third parties | 5,378 | | 628 | | 1,381 | | 2,196 | | 1,159 | | 1,647 | | – | | 768 | | 13,157 | |
| Sales between businesses | 2,329 | | 1,024 | | 14,572 | | 3,229 | | 807 | | 2,875 | | – | | 7,640 | | 32,476 | |
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| | 7,707 | | 1,652 | | 15,953 | | 5,425 | | 1,966 | | 4,522 | | – | | 8,408 | | 45,633 | |
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| Exploration expenditure | 20 | | (1 | ) | 634 | | 132 | | 11 | | 132 | | 17 | | 100 | | 1,045 | |
| Production costs | 1,312 | | 145 | | 2,311 | | 638 | | 155 | | 509 | | – | | 238 | | 5,308 | |
| Production taxes | 492 | | 38 | | 887 | | 295 | | 63 | | – | | – | | 2,079 | | 3,854 | |
| Other costs (income)d | (867 | ) | 90 | | 2,561 | | 478 | | 154 | | 104 | | 32 | | 3,121 | | 5,673 | |
| Depreciation, depletion and amortization | 1,612 | | 213 | | 2,083 | | 685 | | 175 | | 865 | | – | | 510 | | 6,143 | |
| Impairments and (gains) losses on sale of | | | | | | | | | | | | | | | | | | |
| businesses and fixed assets | (450 | ) | (57 | ) | (1,880 | ) | 42 | | (99 | ) | (31 | ) | – | | – | | (2,475 | ) |
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| | 2,119 | | 428 | | 6,596 | | 2,270 | | 459 | | 1,579 | | 49 | | 6,048 | | 19,548 | |
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| Profit before taxatione,f | 5,588 | | 1,224 | | 9,357 | | 3,155 | | 1,507 | | 2,943 | | (49 | ) | 2,360 | | 26,085 | |
| Allocable taxes | 2,567 | | 793 | | 3,136 | | 1,443 | | 472 | | 1,328 | | 3 | | 737 | | 10,479 | |
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| Results of operations | 3,021 | | 431 | | 6,221 | | 1,712 | | 1,035 | | 1,615 | | (52 | ) | 1,623 | | 15,606 | |
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The group’s share of jointly controlled entities’ and associates’ results of operations in 2006 was a profit of $3,302 million after deducting interest of $324 million, taxation of $1,804 million and minority interest of $193 million.
| a | This note contains information relating to oil and natural gas exploration and production activities. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group’s share of jointly controlled entities’ and associates’ activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above. |
| b | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
| c | Sales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty payable in cash. |
| d | Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes, other government take and the fair value gain on embedded derivatives $515 million. |
| e | Excludes accretion expense attributable to exploration and production activities amounting to $153 million. Under IFRS, accretion expense is included in other finance expense in the group income statement. |
| f | The Exploration and Production profit before interest and tax is set out below. |
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| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2006 | |
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| Exploration and production activities | | | | | | | | | | | | | | | | | | |
| Group (as above) | 5,588 | | 1,224 | | 9,357 | | 3,155 | | 1,507 | | 2,943 | | (49 | ) | 2,360 | | 26,085 | |
| Jointly controlled entities and associates | – | | – | | 1 | | 535 | | 33 | | 1 | | 2,730 | | 2 | | 3,302 | |
| Mid-stream activities | 250 | | (14 | ) | (31 | ) | 85 | | (31 | ) | (11 | ) | (24 | ) | 18 | | 242 | |
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| Total profit before interest and tax | 5,838 | | 1,210 | | 9,327 | | 3,775 | | 1,509 | | 2,933 | | 2,657 | | 2,380 | | 29,629 | |
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Back to Contents
51 Oil and natural gas exploration and production activitiesacontinued
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2005 | |
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| | | | Rest of | | | | Rest of | | Asia
| | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Capitalized costs at 31 December | | | | | | | | | | | | | | | | | | |
| Gross capitalized costs | | | | | | | | | | | | | | | | | | |
| Proved properties | 31,552 | | 4,608 | | 46,288 | | 9,585 | | 2,922 | | 12,183 | | – | | 5,184 | | 112,322 | |
| Unproved properties | 276 | | 135 | | 1,547 | | 583 | | 1,124 | | 656 | | 185 | | 155 | | 4,661 | |
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| | 31,828 | | 4,743 | | 47,835 | | 10,168 | | 4,046 | | 12,839 | | 185 | | 5,339 | | 116,983 | |
| Accumulated depreciation | 22,302 | | 2,949 | | 22,016 | | 4,919 | | 1,508 | | 6,112 | | – | | 1,200 | | 61,006 | |
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| Net capitalized costs | 9,526 | | 1,794 | | 25,819 | | 5,249 | | 2,538 | | 6,727 | | 185 | | 4,139 | | 55,977 | |
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The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2005 was $10,670 million.
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| Costs incurred for the year ended 31 December | | | | | | | | | | | | | | | | | |
| Acquisition of properties | | | | | | | | | | | | | | | | | | |
| Proved | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Unproved | – | | – | | 29 | | 34 | | – | | – | | – | | – | | 63 | |
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| | – | | – | | 29 | | 34 | | – | | – | | – | | – | | 63 | |
| Exploration and appraisal costsb | 51 | | 7 | | 606 | | 133 | | 11 | | 264 | | 126 | | 68 | | 1,266 | |
| Development costs | 790 | | 188 | | 2,965 | | 681 | | 186 | | 1,691 | | – | | 1,177 | | 7,678 | |
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| Total costs | 841 | | 195 | | 3,600 | | 848 | | 197 | | 1,955 | | 126 | | 1,245 | | 9,007 | |
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The group’s share of jointly controlled entities’ and associates’ costs incurred in 2005 was $1,205 million: in Russia $845 million and Rest of Americas $360 million.
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Results of operations for the year
ended 31 December | | | | | | | | | | | | | | | | | | |
| Sales and other operating revenuesc | | | | | | | | | | | | | | | | | | |
| Third parties | 4,667 | | 635 | | 2,048 | | 2,260 | | 1,045 | | 1,350 | | – | | 690 | | 12,695 | |
| Sales between businesses | 2,458 | | 976 | | 14,842 | | 2,863 | | 782 | | 2,402 | | – | | 4,796 | | 29,119 | |
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| | 7,125 | | 1,611 | | 16,890 | | 5,123 | | 1,827 | | 3,752 | | – | | 5,486 | | 41,814 | |
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| Exploration expenditure | 32 | | 1 | | 426 | | 84 | | 6 | | 81 | | 37 | | 17 | | 684 | |
| Production costs | 1,082 | | 118 | | 1,814 | | 578 | | 159 | | 460 | | – | | 180 | | 4,391 | |
| Production taxes | 485 | | 33 | | 610 | | 281 | | 54 | | – | | – | | 1,536 | | 2,999 | |
| Other costs (income)d | 1,857 | | (55 | ) | 2,200 | | 537 | | 170 | | 98 | | 8 | | 2,042 | | 6,857 | |
Depreciation, depletion and amortization | 1,548 | | 220 | | 2,288 | | 675 | | 162 | | 542 | | – | | 193 | | 5,628 | |
| Impairments and (gains) losses on sale of | | | | | | | | | | | | | | | | | | |
| businesses and fixed assets | 44 | | (1,038 | ) | 232 | | (133 | ) | – | | – | | 2 | | – | | (893 | ) |
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| | 5,048 | | (721 | ) | 7,570 | | 2,022 | | 551 | | 1,181 | | 47 | | 3,968 | | 19,666 | |
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| Profit before taxationef | 2,077 | | 2,332 | | 9,320 | | 3,101 | | 1,276 | | 2,571 | | (47 | ) | 1,518 | | 22,148 | |
| Allocable taxes | 405 | | 880 | | 3,377 | | 1,390 | | 447 | | 1,043 | | (1 | ) | 409 | | 7,950 | |
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| Results of operations | 1,672 | | 1,452 | | 5,943 | | 1,711 | | 829 | | 1,528 | | (46 | ) | 1,109 | | 14,198 | |
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The group’s share of jointly controlled entities’ and associates’ results of operations in 2005 was a profit of $3,029 million after deducting interest of $226 million, taxation of $1,250 million and minority interest of $104 million.
| a | This note contains information relating to oil and natural gas exploration and production activities. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group’s share of jointly controlled entities’ and associates’ activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above. |
| b | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
| c | Sales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is payable in cash. |
| d | Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes, other government take, the fair value loss on embedded derivatives $1,688 million and a $265 million charge incurred on the cancellation of an intragroup gas supply contract. The UK region includes a $530 million charge offset by corresponding gains primarily in the US, relating to the group’s self-insurance programme. |
| e | Excludes accretion expense attributable to exploration and production activities amounting to $122 million. Under IFRS, accretion expense is included in other finance expense in the group income statement. |
| f | The Exploration and Production profit before interest and tax is set out below. |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2005 | |
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| Exploration and production activities | | | | | | | | | | | | | | | | | | |
| Group (as above) | 2,077 | | 2,332 | | 9,320 | | 3,101 | | 1,276 | | 2,571 | | (47 | ) | 1,518 | | 22,148 | |
| Jointly controlled entities and associates | – | | – | | – | | 309 | | 35 | | – | | 2,685 | | – | | 3,029 | |
| Mid-stream activities | 52 | | (11 | ) | 172 | | 148 | | (20 | ) | (39 | ) | (1 | ) | 24 | | 325 | |
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| Total profit before interest and tax | 2,129 | | 2,321 | | 9,492 | | 3,558 | | 1,291 | | 2,532 | | 2,637 | | 1,542 | | 25,502 | |
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Back to Contents
51 Oil and natural gas exploration and production activitiesacontinued
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2004 | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Capitalized costs at 31 December | | | | | | | | | | | | | | | | | | |
| Gross capitalized costs | | | | | | | | | | | | | | | | | | |
| Proved properties | 30,639 | | 4,691 | | 43,011 | | 10,450 | | 2,892 | | 10,401 | | – | | 3,834 | | 105,918 | |
| Unproved properties | 300 | | 170 | | 1,395 | | 456 | | 1,240 | | 526 | | 119 | | 105 | | 4,311 | |
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| | 30,939 | | 4,861 | | 44,406 | | 10,906 | | 4,132 | | 10,927 | | 119 | | 3,939 | | 110,229 | |
| Accumulated depreciation | 20,780 | | 2,794 | | 19,713 | | 5,546 | | 1,350 | | 5,573 | | – | | 1,014 | | 56,770 | |
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| Net capitalized costs | 10,159 | | 2,067 | | 24,693 | | 5,360 | | 2,782 | | 5,354 | | 119 | | 2,925 | | 53,459 | |
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The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2004 was $11,013 million.
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| Costs incurred for the year ended 31 December | | | | | | | | | | | | | | | | | |
| Acquisition of properties | | | | | | | | | | | | | | | | | | |
| Proved | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Unproved | 2 | | – | | 58 | | 5 | | – | | 13 | | – | | – | | 78 | |
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| | 2 | | – | | 58 | | 5 | | – | | 13 | | – | | – | | 78 | |
| Exploration and appraisal costsb | 51 | | 17 | | 423 | | 199 | | 85 | | 142 | | 113 | | 9 | | 1,039 | |
| Development costs | 679 | | 262 | | 3,247 | | 527 | | 88 | | 1,460 | | – | | 1,007 | | 7,270 | |
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| Total costs | 732 | | 279 | | 3,728 | | 731 | | 173 | | 1,615 | | 113 | | 1,016 | | 8,387 | |
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The group’s share of jointly controlled entities’ and associates’ costs incurred in 2004 was $1,102 million: in Russia $773 million and Rest of Americas $329 million.
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Results of operations for the year
ended 31 December | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Sales and other operating revenuesc | | | | | | | | | | | | | | | | | | |
| Third parties | 3,458 | | 626 | | 1,735 | | 1,776 | | 977 | | 492 | | 5 | | 403 | | 9,472 | |
| Sales between businesses | 2,424 | | 609 | | 11,794 | | 2,556 | | 530 | | 1,439 | | – | | 2,912 | | 22,264 | |
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| | 5,882 | | 1,235 | | 13,529 | | 4,332 | | 1,507 | | 1,931 | | 5 | | 3,315 | | 31,736 | |
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| Exploration expenditure | 26 | | 25 | | 361 | | 141 | | 14 | | 45 | | 17 | | 8 | | 637 | |
| Production costs | 901 | | 117 | | 1,428 | | 535 | | 142 | | 323 | | – | | 131 | | 3,577 | |
| Production taxes | 273 | | 30 | | 477 | | 239 | | 45 | | – | | – | | 1,023 | | 2,087 | |
| Other costs (income)d | (211 | ) | 38 | | 1,884 | | 458 | | 96 | | 122 | | (3 | ) | 1,380 | | 3,764 | |
| Depreciation, depletion and amortization | 1,524 | | 172 | | 2,268 | | 611 | | 174 | | 287 | | – | | 121 | | 5,157 | |
Impairments and (gains) losses on sale of businesses and fixed assets | 21 | | 1 | | 344 | | (55 | ) | 113 | | 48 | | – | | (3 | ) | 469 | |
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| | 2,534 | | 383 | | 6,762 | | 1,929 | | 584 | | 825 | | 14 | | 2,660 | | 15,691 | |
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| Profit before taxationef | 3,348 | | 852 | | 6,767 | | 2,403 | | 923 | | 1,106 | | (9 | ) | 655 | | 16,045 | |
| Allocable taxes | 1,242 | | 534 | | 2,103 | | 859 | | (4 | ) | 441 | | 2 | | 150 | | 5,327 | |
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| Results of operations | 2,106 | | 318 | | 4,664 | | 1,544 | | 927 | | 665 | | (11 | ) | 505 | | 10,718 | |
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The group’s share of jointly controlled entities’ and associates’ results of operations in 2004 was a profit of $1,814 million after deducting interest of $189 million, taxation of $969 million and minority interest of $43 million.
| a | This note contains information relating to oil and natural gas exploration and production activities. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group’s share of jointly controlled entities’ and associates’ activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above. |
| b | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs,which are charged to income as incurred. |
| c | Sales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is payable in cash. |
| d | Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes and other government take. |
| e | Excludes accretion expense attributable to exploration and production activities amounting to $120 million. Under IFRS, accretion expense is included in other finance expense in the group income statement. |
| f | The Exploration and Production profit before interest and tax is set out below. |
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2004 | |
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Exploration and production activities | | | | | | | | | | | | | | | | | | |
| Group (as above) | 3,348 | | 852 | | 6,767 | | 2,403 | | 923 | | 1,106 | | (9 | ) | 655 | | 16,045 | |
| Jointly controlled entities and associates | – | | – | | – | | 113 | | 36 | | – | | 1,665 | | – | | 1,814 | |
| Mid-stream activities | 105 | | (15 | ) | 40 | | 123 | | (50 | ) | (19 | ) | – | | 42 | | 226 | |
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| Total profit before interest and tax | 3,453 | | 837 | | 6,807 | | 2,639 | | 909 | | 1,087 | | 1,656 | | 697 | | 18,085 | |
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Back to Contents
| | | Additional information for US reporting |
52 Suspended exploration well costs
Included within the total exploration expenditure of $4,110 million (2005 $4,008 million and 2004 $3,761 million) shown as part of intangible assets (see Note 28) is an amount of $1,863 million (2005 $1,931 million and 2004 $1,680 million) representing costs directly associated with exploration wells.
The carried costs of exploration wells are subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. In evaluating whether costs incurred meet the criteria for initial and continued capitalization management uses two main criteria: (a) that exploration drilling is still under way or firmly planned, or (b) that it either has been determined, or work is underway to determine, that the discovery is economically viable, based on a range of technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing.
The following table provides the year-end balances and movements for suspended exploration well costs.
| | | | | | $ million | |
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| Capitalized exploration well costs | | | | | | |
| At 1 January | 1,931 | | 1,680 | | 1,698 | |
| Additions pending determination of proved reserves | 590 | | 565 | | 391 | |
| Exploration well costs written off in the year | (168 | ) | (81 | ) | (84 | ) |
| Costs of exploration wells divested in the year | (36 | ) | (72 | ) | (34 | ) |
| Reclassified to tangible assets following determination of proved reserves | (251 | ) | (161 | ) | (291 | ) |
| Reclassified to investment in jointly controlled entity | (203 | ) | – | | – | |
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| At 31 December | 1,863 | | 1,931 | | 1,680 | |
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The following table provides an ageing profile of suspended exploration wells.
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| At 31 December | | | 2006 | | | | 2005 | | | | 2004 | |
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| | Cost | | Wells | | Cost | | Wells | | Cost | | Wells | |
| | $ million | | gross | | $ million | | gross | | $ million | | gross | |
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| Age | | | | | | | | | | | | |
| Less than 1 year | 611 | | 45 | | 593 | | 46 | | 411 | | 26 | |
| 1 to 5 years | 736 | | 64 | | 823 | | 69 | | 787 | | 81 | |
| 6 to 10 years | 267 | | 37 | | 309 | | 42 | | 292 | | 29 | |
| More than 10 years | 249 | | 26 | | 206 | | 20 | | 190 | | 18 | |
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| Total | 1,863 | | 172 | | 1,931 | | 177 | | 1,680 | | 154 | |
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The following table provides an analysis of the amount of costs directly associated with exploration wells.
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| | | | | | 2006 | | | | | | 2005 | | | | | | 2004 | |
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| | Cost | | Wells | | | | Cost | | Wells | | | | Cost | | Wells | | | |
| | $ million | | gross | | Projects | | $ million | | gross | | Projects | | $ million | | gross | | Projects | |
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| Exploration well costs | | | | | | | | | | | | | | | | | | |
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Projects with first capitalized exploration well
drilled in the 12 months ending 31 December | 188 | | 17 | | 12 | | 451 | | 31 | | 14 | | 290 | | 15 | | 12 | |
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Other projects with recent or planned drilling
activity | 894 | | 86 | | 21 | | 718 | | 65 | | 20 | | 400 | | 36 | | 13 | |
| Projects with completed exploration activity | 781 | | 69 | | 27 | | 762 | | 81 | | 28 | | 990 | | 103 | | 41 | |
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| At 31 December | 1,863 | | 172 | | 60 | | 1,931 | | 177 | | 62 | | 1,680 | | 154 | | 66 | |
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Exploration projects frequently involve the drilling of multiple wells over a number of years, and several discoveries may be grouped into a single development project. The table above shows a total of 48 projects which have exploration well costs which have been capitalized for more than twelve months as at 31 December 2006. Of these, there are 21 projects where exploratory wells have been drilled in the preceding 12 months or further exploratory drilling is planned in the next year. Projects with completed exploration activity comprise a total of 27 projects, whose costs totalled $781 million at 31 December 2006. Details of the activities being undertaken to progress these projects towards development are shown below.
Back to Contents
52 Suspended exploration well costscontinued
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| | | | | | | | | Anticipated | | | |
| | | | | 2006 | | Years | | year of | | | |
| | | Cost | | wells | | wells | | development | | | |
| Country | Project | $ million | | gross | | drilled | | project sanction | | Comment | |
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| Angola | Chumbo | 26 | | 2 | | 2003-2005 | | 2008-2009 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development option identified andunder evaluation; development plan for FPSO submitted. | |
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| | Plutao/Saturno/Marte/ | 51 | | 5 | | 2002-2005 | | 2007 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development option using FPSOidentified and under evaluation. | |
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| | | 77 | | 7 | | | | | | | |
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| Colombia | Volcanera | 43 | | 1 | | 1993 | | 2009 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspectsof project in progress; development options identified andunder evaluation; planned phased development linked toneighbouring field using existing infrastructure; seismicsurvey in process. | |
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| | | 43 | | 1 | | | | | | | |
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| Egypt | Ras El Bar Seth | 3 | | 1 | | 1995 | | 2009-2012 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development options identifiedand under evaluation; development planned throughtieback to existing infrastructure; gas sale agreement inplace. | |
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| | Western Mediterranean | 14 | | 3 | | 2002-2004 | | 2008-2017 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development options identifiedand under evaluation; seismic survey completed and underreview; concession agreement amendment negotiationsunder way. | |
| | Block B | | | | | | | | | |
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| | | 17 | | 4 | | | | | | | |
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| Indonesia | Tangguh Phase II | 51 | | 9 | | 1994-1997 | | 2009-2011 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspectsof project in progress; onshore and offshore developmentoptions identified and under evaluation. This is the secondphase of the LNG project which is currently underdevelopment. | |
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| | | 51 | | 9 | | | | | | | |
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| Norway | Skarv/Snadd | 72 | | 8 | | 1998-2002 | | 2007 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development options identifiedand under evaluation; planned development with floatingproduction system and export infrastructure agreed withpartners. | |
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| | | 72 | | 8 | | | | | | | |
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| Trinidad | Chachalaca | 48 | | 1 | | 2005 | | 2007 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspectsof project in progress; development option selected. | |
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| | Coconut | 47 | | 1 | | 2005 | | 2010+ | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspectsof project in progress; development options identified andunder evaluation; planned subsea tieback to existinginfrastructure. | |
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| | Corallita/Lantana | 24 | | 2 | | 1996 | | 2007-2008 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development options identifiedand under evaluation; planned subsea tieback to existinginfrastructure fields dedicated to LNG gas contractdelivery; dependent upon capacity in existing infrastruture. | |
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| | Manakin | 21 | | 1 | | 2000 | | 2010+ | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspectsof project in progress; development options identified andunder evaluation; planned subsea tieback to existingproduction facilities and LNG train; inter-governmentaldiscussions on unitization continue. | |
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| | | 140 | | 5 | | | | | | | |
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Back to Contents
52 Suspended exploration well costs continued
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| | | | | | | | | Anticipated | | | |
| | | | | 2006 | | Years | | year of | | | |
| | | Cost | | wells | | wells | | development | | | |
| Country | Project | $ million | | gross | | drilled | | project sanction | | Comment | |
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| UK | Andrew | 14 | | 1 | | 1998 | | 2007 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development options identifiedand under evaluation; development awaiting capacity inexisting infrastructure; negotiations under way for gassales contract. | |
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| | Devenick | 90 | | 3 | | 1983-2001 | | 2007 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspectsof project in progress; development options identified andunder evaluation; development expected in conjunctionwith Harding Gas Project nearby. | |
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| | Puffin | 29 | | 9 | | 1982-1991 | | 2008-2010 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; further assessment of economicand developmental aspects of project to be undertaken;sub-surface and feasibility review under way; developmentawaiting capacity in existing infrastructure. | |
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| | Suilven | 20 | | 3 | | 1995-1998 | | 2010-2011 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic anddevelopmental aspects of project in progress;development anticipated to be by tieback to existingproduction vessel; awaiting capacity in existinginfrastructure. | |
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| | | 153 | | 16 | | | | | | | |
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| US | Entrada | 24 | | 2 | | 2000 | | 2007 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development options identifiedand under evaluation; expected development as subseatieback to facilities installed in 2005; negotiations withinfrastructure owners for product handling agreement areunder way. | |
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| | Liberty | 20 | | 1 | | 1997 | | 2008 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; development options identifiedand under evaluation; planned tieback via extended reachdrilling from existing infrastructure; Memorandums ofUnderstanding with two key permitting agencies havebeen secured. | |
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| | Mad Dog Deep | 49 | | 1 | | 2005 | | 2009-2011 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic anddevelopmental aspects of project under way. | |
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| | Mad Dog Southwest Ridge | 33 | | 3 | | 2005 | | 2008 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspects ofproject under way; development options identified and underevaluation; development expected to be by subsea tieback. | |
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| Vietnam | Hai Thach | 65 | | 3 | | 1995-2002 | | 2008-2009 | | Assessment of hydrocarbon quantities as potentiallycommercial completed; assessment of economic aspectsof project in place; development options identified andunder evaluation; licence extension under negotiation. | |
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| | Kim Cuong Tay | 13 | | 1 | | 1995 | | 2010-2012 | | Initial assessment of hydrocarbon quantities as potentiallycommercial completed; further assessment ofdevelopmental aspects of project to be undertaken; furtherseismic study planned for 2007. | |
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| Miscellaneous | | | | | | | | | | | |
| smaller projects | | | | | | | | | | |
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| Certain projects which were classified as projects with completed exploration drilling activity at 31 December 2005 are not classified as such at 31 December 2006: |
| – | The following projects were sanctioned for development in 2006: Florena/Pauto in Colombia; Ras El Bar/Taurt in Egypt; Cashima and Red Mango inTrinidad; and Dorado in the US. |
| – | In Egypt, further exploratory drilling was undertaken in 2006 on the Temsah project, and $8 million relating to part of the project was sanctionedin 2006. |
| – | In Angola, the Bavuca/Kakocha/Mavacola/Mbulumbumba/Vicango project was regrouped into two separate projects, with one project planningfurther exploratory drilling in 2007 and an appraisal well having been drilled on the other in 2006. |
| – | In the US, the Point Thompson/Sourdough project was written off resulting in an expense of $27 million in respect of the well costs. |
Back to Contents
53 US GAAP reconciliation
The consolidated financial statements of the BP group are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted for use by the EU, which differ in certain respects from US generally accepted accounting principles (US GAAP). IFRS as adopted by the EU differs in certain respects from IFRS as issued by the International Accounting Standards Board (IASB). However, the consolidated financial statements for the years presented would be no different had the group applied IFRS as issued by the IASB.
The following is a summary of the adjustments to profit for the year attributable to BP shareholders and to BP shareholders’ equity that would be required if US GAAP had been applied instead of IFRS.
| Profit for the year | $ million except per share amounts | |
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| For the year ended 31 December | 2006 | | 2005 | | 2004 | |
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| Profit as reported to accord with IFRS | 22,315 | | 22,026 | | 17,075 | |
| Adjustments | | | | | | |
| Deferred taxation/business combinations (a) | (224 | ) | (496 | ) | (517 | ) |
| Provisions (b) | 177 | | 9 | | (80 | ) |
| Oil and natural gas reserves differences (c) | (243 | ) | 11 | | 30 | |
| Goodwill and intangible assets (d) | 13 | | – | | (61 | ) |
| Derivative financial instruments (e) | 142 | | 87 | | (337 | ) |
| Inventory valuation (f) | 162 | | (232 | ) | 162 | |
| Gain arising on asset exchange (g) | (10 | ) | (12 | ) | (107 | ) |
| Pensions and other post-retirement benefits (h) | (873 | ) | (486 | ) | (47 | ) |
| Impairments (i) | (332 | ) | (378 | ) | 677 | |
| Equity-accounted investments (j) | (104 | ) | (255 | ) | 147 | |
| Consolidation of variable interest entities (l) | (5 | ) | – | | – | |
| Major maintenance expenditure (m) | – | | – | | 217 | |
| Share-based payments (n) | 92 | | 6 | | 24 | |
| Other | 6 | | 156 | | (93 | ) |
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| Profit for the year before cumulative effect of accounting change as adjusted to accord with US GAAP | 21,116 | | 20,436 | | 17,090 | |
| Cumulative effect of accounting change | | | | | | |
| Major maintenance expenditure (m) | – | | (794 | ) | – | |
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| Profit for the year as adjusted to accord with US GAAP | 21,116 | | 19,642 | | 17,090 | |
| Dividend requirements on preference shares | 2 | | 2 | | 2 | |
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| Profit for the year attributable to ordinary shares as adjusted to accord with US GAAP | 21,114 | | 19,640 | | 17,088 | |
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| Per ordinary share – cents | | | | | | |
| Basic – before cumulative effect of accounting change | 105.42 | | 96.72 | | 78.31 | |
| Cumulative effect of accounting change | – | | (3.76 | ) | – | |
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| | 105.42 | | 92.96 | | 78.31 | |
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| Diluted – before cumulative effect of accounting change | 104.63 | | 95.62 | | 76.88 | |
| Cumulative effect of accounting change | – | | (3.71 | ) | – | |
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| | 104.63 | | 91.91 | | 76.88 | |
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| Per American depositary share – centsa | | | | | | |
| Basic – before cumulative effect of accounting change | 632.52 | | 580.32 | | 469.86 | |
| Cumulative effect of accounting change | – | | (22.56 | ) | – | |
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| | 632.52 | | 557.76 | | 469.86 | |
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| Diluted – before cumulative effect of accounting chane | 627.78 | | 573.72 | | 461.28 | |
| Cumulative effect of accounting change | – | | (22.26 | ) | – | |
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| | 627.78 | | 551.46 | | 461.28 | |
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| a | One American depositary share is equivalent to six ordinary shares. |
Back to Contents
53 US GAAP reconciliation continued
| BP shareholders’ equity | | | $ million | |
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| At 31 December | 2006 | | 2005 | |
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| BP shareholders’ equity as reported to accord with IFRS | 84,624 | | 79,661 | |
| Adjustments | | | | |
| Deferred taxation/business combinations (a) | 1,801 | | 2,025 | |
| Provisions (b) | 63 | | (112 | ) |
| Oil and natural gas reserves differences (c) | (202 | ) | 41 | |
| Goodwill and intangible assets (d) | 248 | | 171 | |
| Derivative financial instruments (e) | 202 | | 225 | |
| Inventory valuation (f) | (5 | ) | (167 | ) |
| Gain arising on asset exchange (g) | 229 | | 239 | |
| Pensions and other post-retirement benefits (h) | – | | 3,146 | |
| Impairments (i) | 2 | | 327 | |
| Equity-accounted investments (j) | (160 | ) | (43 | ) |
| Consolidation of variable interest entities (l) | (5 | ) | – | |
| Share-based payments (n) | (254 | ) | (334 | ) |
| Other | (26 | ) | (32 | ) |
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| BP shareholders’ equity as adjusted to accord with US GAAP | 86,517 | | 85,147 | |
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Comprehensive income
The components of comprehensive income, net of related tax, are as follows: | | | | | | |
| | | | | | $ million | |
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| For the year ended 31 December | 2006 | | 2005 | | 2004 | |
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| Profit for the year as adjusted to accord with US GAAP | 21,116 | | 19,642 | | 17,090 | |
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Currency translation differences net of tax benefit (expense) of $(203) million (2005 $328 million and
2004 $(208) million) | 1,824 | | (2,865 | ) | 2,143 | |
| Investments | | | | | | |
| Unrealized gains net of tax benefit (expense) of $(83) million (2005 $(110) million and 2004 $(71) million) | 480 | | 291 | | 141 | |
| Unrealized losses net of tax benefit (expense) of $nil (2005 $16 million and 2004 $nil) | (2 | ) | (42 | ) | – | |
Less: reclassification adjustment for gains included in net income net of tax benefit (expense) of $191 million
(2005 $22 million and 2004 $627 million) | (504 | ) | (59 | ) | (1,165 | ) |
| Currency translation differences net of tax benefit (expense) of $nil (2005 $nil and 2004 $nil) | 27 | | (32 | ) | – | |
Unrealized gains (losses) on cash flow hedges net of tax benefit (expense) of $(3) million (2005 $63 million and
2004 $nil) | 102 | | (131 | ) | – | |
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Minimum pension liability adjustment net of tax benefit (expense) of $44 million (2005 $(94) million and
2004 $130 million) | 82 | | 249 | | (838 | ) |
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| Comprehensive income | 23,125 | | 17,053 | | 17,371 | |
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| Accumulated other comprehensive income | | | $ million | |
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| At 31 December | 2006 | | 2005 | |
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| Currency translation differences | 3,320 | | 1,496 | |
| Net unrealized gains on investments | 386 | | 385 | |
| Unrealized losses on cash flow hedges | (29 | ) | (131 | ) |
| Minimum pension liability adjustment | – | | (866 | ) |
| Funded status of defined benefit pension and other post-retirement benefit plansb c | (1,383 | ) | – | |
|
|
|
|
|
| Accumulated other comprehensive income | 2,294 | | 884 | |
|
|
|
|
|
| b | The amount reported for the funded status of defined benefit pension and other post-retirement benefit plans at 31 December 2006 includes $(599) million resulting from the adoption of FASB Statement of Financial Accounting Standards (SFAS) No. 158 ‘Employers’ Accounting for Defined Benefit Pension and Other Post-retirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)’. Further information on the effects of adoption of SFAS 158 is provided in note (h) Pensions and other post-retirement benefits. |
| c | Includes $(13) million relating to equity-accounted entities. |
Consolidated statement of cash flows
The group’s financial statements include a consolidated cash flow statement in accordance with IAS 7 ‘Cash Flow Statements’. The statement prepared under IAS 7 presents substantially the same information as that required under FASB SFAS No. 95 ‘Statement of Cash Flows’; however, as permitted under IAS 7, the group includes payments in respect of capitalized interest in operating activities. Under SFAS 95, these payments are treated as cash outflows for investing activities.
The adjustments to the group’s cash flow statement for the year to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| For the year ended 31 December | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Net cash provided by operating activities | 478 | | 351 | | 204 | |
| Net cash provided by (used in) investing activities | (478 | ) | (351 | ) | (204 | ) |
|
|
|
|
|
|
|
| Increase (decrease) in cash and cash equivalents | – | | – | | – | |
|
|
|
|
|
|
|
Back to Contents
53 US GAAP reconciliation continued
The principal differences between IFRS and US GAAP for BP group reporting relate to the following:
(a) Deferred taxation/business combinations
Under IFRS, deferred tax assets and liabilities are recognized for the difference between the assigned values and the tax bases of the assets and liabilities recognized in a purchase business combination. IFRS 3 ‘Business Combinations’ typically requires the offset to the recognition of such deferred tax assets and liabilities to be adjusted against goodwill. However, under the exemptions contained in IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’, business combinations prior to the group’s date of transition to IFRS were not restated in accordance with IFRS 3 and the offset was taken as an adjustment to shareholders’ equity at the date of transition to IFRS.
Under US GAAP, deferred tax assets or liabilities are also recognized for the difference between the assigned values and the tax bases of the assets and liabilities recognized in a purchase business combination. SFAS No. 141 ‘Business Combinations’, requires that the offset be recognized against goodwill. As such, the treatment adopted under IFRS 1 as compared with SFAS 141 creates a difference related to business combinations accounted for under the purchase method that occurred prior to the group’s date of transition to IFRS.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Depreciation, depletion and amortization | 397 | | 254 | | 2,048 | |
| Taxation | (173 | ) | 242 | | (1,531 | ) |
| Profit for the year | (224 | ) | (496 | ) | (517 | ) |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Property, plant and equipment | 3,062 | | 3,459 | |
| Deferred tax liabilities | 1,261 | | 1,434 | |
| BP shareholders’ equity | 1,801 | | 2,025 | |
|
|
|
|
|
The major components of deferred tax liabilities and assets on a US GAAP basis at 31 December were as follows.
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Deferred tax liability | | | | |
| Depreciation | 22,295 | | 20,782 | |
| Pension plan surplus | 1,733 | | 1,371 | |
| Other taxable temporary differences | 4,687 | | 4,214 | |
|
|
|
|
|
| | 28,715 | | 26,367 | |
|
|
|
|
|
| Deferred tax asset | | | | |
| Petroleum revenue tax | (457 | ) | (407 | ) |
| Pension plan and other post-retirement benefit plan deficits | (2,012 | ) | (1,154 | ) |
| Decommissioning, environmental and other provisions | (2,942 | ) | (2,292 | ) |
| Derivative financial instruments | (928 | ) | (770 | ) |
| Tax credit and loss carry forward | (3,920 | ) | (3,533 | ) |
| Other deductible temporary differences | (2,623 | ) | (1,591 | ) |
|
|
|
|
|
| Gross deferred tax asset | (12,882 | ) | (9,747 | ) |
| Valuation allowance | 3,830 | | 3,222 | |
|
|
|
|
|
| Net deferred tax asset | (9,052 | ) | (6,525 | ) |
|
|
|
|
|
| Net deferred tax liability | 19,663 | | 19,842 | |
|
|
|
|
|
(b) Provisions
Under IFRS, provisions for decommissioning and environmental liabilities are measured on a discounted basis if the effect of the time value of money is material. In accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’, the provisions for decommissioning and environmental liabilities are estimated using costs based on current prices and discounted using rates that take into consideration the time value of money and risks inherent in the liability. The periodic unwinding of the discount is included in other finance expense. Similarly, the effect of a change in the discount rate is included in other finance expense in connection with all provisions other than decommissioning liabilities.
Upon initial recognition of a decommissioning provision, a corresponding amount is also recognized as an item of property, plant and equipment and is subsequently depreciated as part of the capital cost of the facilities. Adjustments to the decommissioning liabilities, associated with changes to the future cash flow assumptions or changes in the discount rate, are reflected as increases or decreases to the corresponding item of property, plant and equipment and depreciated prospectively over the asset’s remaining economic useful life.
Under US GAAP, decommissioning liabilities are recognized in accordance with SFAS No. 143 ‘Accounting for Asset Retirement Obligations’. SFAS 143 is similar to IAS 37 and requires that when an asset retirement liability is recognized, a corresponding amount is capitalized and depreciated as an additional cost of the related asset. The liability is measured based on the risk-adjusted future cash outflows discounted using a credit-adjusted risk-free rate. The unwinding of the discount is included in operating profit for the period. Unlike IFRS, subsequent changes to the discount rate do not impact the carrying value of the asset or liability. Subsequent changes to the estimates of the timing or amount of future cash flows, resulting in an increase to the asset and liability, are remeasured using updated assumptions related to the credit-adjusted risk-free rate.
In addition, the use of different oil and natural gas reserves volumes between US GAAP and IFRS until 1 October 2006 (see note (c) Oil and natural gas reserves differences) resulted in different field lives and hence differences in the manner in which the subsequent unwinding of the discount and the depreciation of the corresponding assets associated with decommissioning provisions were recognized.
Back to Contents
53 US GAAP reconciliation continued
Under US GAAP, environmental liabilities are discounted only where the timing and amounts of payments are fixed and reliably determinable.
Under IFRS, an expected loss is recognized immediately as a provision for an executory contract if the unavoidable costs of meeting the obligations under the contract exceed the economic benefits expected to be received under it. Under US GAAP, an expected loss can only be recognized if the contract is within the scope of authoritative literature that specifically provides for such accruals. The group has recognized losses under IFRS on certain sales contracts with fixed-price ceilings which do not meet loss recognition criteria under US GAAP.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Production and manufacturing expenses and depreciation, depletion and amortization | 56 | | 201 | | 254 | |
| Distribution and administration expenses | (108 | ) | – | | – | |
| Other finance (income) expense | (245 | ) | (201 | ) | (196 | ) |
| Taxation | 120 | | (9 | ) | 22 | |
| Profit for the year | 177 | | 9 | | (80 | ) |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Property, plant and equipment | (2,065 | ) | (1,842 | ) |
| Provisions | (2,184 | ) | (1,666 | ) |
| Deferred tax liabilities | 56 | | (64 | ) |
| BP shareholders’ equity | 63 | | (112 | ) |
|
|
|
|
|
The following data summarizes the movements in the asset retirement obligations, as adjusted to accord with US GAAP.
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| At 1 January | 4,429 | | 3,898 | |
| Exchange adjustments | 9 | | 4 | |
| New provisions/adjustment to provisions | 1,679 | | 554 | |
| Unwinding of discount | 280 | | 237 | |
| Utilized/deleted | (360 | ) | (264 | ) |
|
|
|
|
|
| At 31 December | 6,037 | | 4,429 | |
|
|
|
|
|
(c) Oil and natural gas reserves differences
The group’s past practice was to use the UK accounting rules contained in the Statement of Recommended Practice ‘Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities’ (SORP) for estimating oil and natural gas reserves for accounting and reporting purposes. These rules are different in certain respects from the corresponding SEC rules. In particular, the SEC requires the use of year-end prices, whereas under SORP the group used long-term planning prices. The consequential difference in reserves volumes resulted in different charges for depreciation, depletion and amortization (DD&A) between IFRS and US GAAP.
At the end of 2006, the group adopted the SEC rules for estimating oil and natural gas reserves for IFRS accounting and reporting purposes and the charge for DD&A was calculated on this basis for the last three months of the year. This is a change in accounting estimate and the impact of the change is applied prospectively. Differences in charges for DD&A between IFRS and US GAAP will continue due to the difference in net book values of the underlying oil and natural gas properties.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Gain on sale of businesses and fixed assets | (198 | ) | – | | – | |
| Depreciation, depletion and amortization | 201 | | (20 | ) | (48 | ) |
| Taxation | (156 | ) | 9 | | 18 | |
| Profit for the year | (243 | ) | 11 | | 30 | |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Property, plant and equipment | (331 | ) | 68 | |
| Deferred tax liabilities | (129 | ) | 27 | |
| BP shareholders’ equity | (202 | ) | 41 | |
|
|
|
|
|
US GAAP requires the unit-of-production depreciation calculation to be based on development expenditure incurred to date and proved developed reserves. Where production commences before all development wells are drilled, a portion of the development costs incurred to date is excluded from the calculation. For the group’s portfolio of fields there is no material difference between the group’s charge for unit-of-production depreciation determined on an IFRS basis and on a US GAAP basis.
Back to Contents
53 US GAAP reconciliation continued
(d) Goodwill and intangible assets
For the purposes of US GAAP, the group accounts for goodwill according to SFAS No. 141 ‘Business Combinations’, and SFAS No. 142 ‘Goodwill and Other Intangible Assets’. For the purposes of IFRS, the group accounts for goodwill under the provisions of IFRS 3 ‘Business Combinations’ and IAS 38 ‘Intangible Assets’. As a result of the transition rules available under IFRS 1, the group did not restate its past business combinations in accordance with IFRS 3 and assumed its UK GAAP carrying amount for goodwill as its IFRS carrying amount upon transition to IFRS, at 1 January 2003.
Under US GAAP, goodwill and other indefinite lived intangible assets have not been amortized since 31 December 2001. Such assets are subject to periodic impairment testing. The group has goodwill, but does not have any other intangible assets with indefinite lives. Under IFRS, goodwill amortization ceased from 1 January 2003.
The movement in the goodwill difference during 2006 is the result of movements in foreign exchange rates and a difference in the amount of goodwill allocated to the Gulf of Mexico Shelf assets sold.
During the fourth quarter of 2006 the group completed a goodwill impairment review using the two-step process prescribed in US GAAP. The first step includes a comparison of the fair value of a reporting unit to its carrying value, including goodwill. When the carrying value exceeds the fair value, the goodwill of the reporting unit is potentially impaired and the second step is then completed in order to measure the impairment loss, if any. No impairment charge resulted from this review.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Gain on sale of businesses and fixed assets | 13 | | – | | – | |
| Depreciation, depletion and amortization | – | | – | | 61 | |
| Profit for the year | 13 | | – | | (61 | ) |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Goodwill | 248 | | 171 | |
| BP shareholders’ equity | 248 | | 171 | |
|
|
|
|
|
In accordance with group accounting practice, exploration licence acquisition costs are capitalized initially as an intangible asset and are amortized over the estimated period of exploration. Where proved reserves of oil or natural gas are determined and development is sanctioned, the unamortized cost is transferred to property, plant and equipment. Where exploration is unsuccessful, the unamortized cost is charged against income. At 31 December 2006 and 31 December 2005, exploration licence acquisition costs included in the group’s property, plant and equipment and intangible assets, net of accumulated amortization were as follows.
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Exploration licence acquisition cost included in non-current assets (net of accumulated amortization) | | | | |
| Property, plant and equipment | 1,076 | | 1,201 | |
| Intangible assets | 639 | | 597 | |
|
|
|
|
|
Changes to the net book amount of exploration expenditure, goodwill and other intangible assets, as adjusted to accord with US GAAP, during the years ended 31 December 2006 and 2005 are shown below.
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | Additional | | | | | |
| | | | | | minimum | | | | | |
| | Exploration | | | | pension | | Other | | | |
| | expenditure | | Goodwill | | liability (h) | | intangibles | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Net book amount | | | | | | | | | | |
| At 1 January 2005 | 3,761 | | 11,535 | | 39 | | 443 | | 15,778 | |
| Amortization expense | (305 | ) | – | | – | | (161 | ) | (466 | ) |
| Other movements | 552 | | (862 | ) | (12 | ) | 482 | | 160 | |
|
|
|
|
|
|
|
|
|
|
|
| At 1 January 2006 | 4,008 | | 10,673 | | 27 | | 764 | | 15,472 | |
| Amortization expense | (732 | ) | – | | – | | (217 | ) | (949 | ) |
| Other movements | 834 | | 476 | | (27 | ) | 589 | | 1,872 | |
|
|
|
|
|
|
|
|
|
|
|
| At 31 December 2006 | 4,110 | | 11,149 | | – | | 1,136 | | 16,395 | |
|
|
|
|
|
|
|
|
|
|
|
Amortization expense relating to other intangibles is expected to be in the range of $200-250 million in each of the succeeding five years.
Back to Contents
53 US GAAP reconciliation continued
(e) Derivative financial instruments
Under IFRS, the group accounts for its derivative financial instruments under IAS 39 ‘Financial Instruments: Recognition and Measurement’. IAS 39 requires that derivative financial instruments be measured at fair value and changes in fair value are either recognized in the income statement or directly in equity (other comprehensive income) depending on the classification of the instrument. Changes in the fair value of derivatives held for trading purposes or those not designated or effective as hedges are recognized in the income statement.
Changes in the fair value of derivatives designated and effective as cash flow hedges are recognized directly in equity (other comprehensive income). Amounts recorded in equity are transferred to the income statement when the hedged transaction affects profit or loss. Where the hedged item is the cost of a non-financial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the non-financial asset or liability.
Changes in the fair value of derivatives designated and effective as fair value hedges are recognized in the income statement. The carrying amount of the hedged item is adjusted for gains and losses attributable to the risk being hedged with the corresponding gains and losses recognized in the income statement.
On adoption of IAS 39 on 1 January 2005, all cash flow and fair value hedges that previously qualified for hedge accounting under UK GAAP were recorded on the balance sheet at fair value with the offset recorded through equity.
Under US GAAP all derivative financial instruments are accounted for under SFAS No. 133 ‘Accounting for Derivative Instruments and Hedging Activities’ and recorded on the balance sheet at their fair value. Similar to IAS 39, SFAS 133 requires that changes in the fair value of derivatives are recorded each period in the income statement or other comprehensive income, depending on whether the instrument is designated as part of a hedge transaction.
Prior to 1 January 2005, the group did not designate any of its derivative financial instruments as part of hedged transactions under SFAS 133. As a result, all changes in fair value were recognized in the income statement. A difference therefore exists between the treatment applied under SFAS 133 and that upon initial adoption of IAS 39 associated with those specific derivative instruments. This difference will remain until these individual derivative transactions mature.
Additionally, under IFRS, hedge accounting can be applied to certain centrally-hedged foreign currency exposures. Under US GAAP, hedge accounting can be applied only where the companies between the central treasury and the entity having the foreign currency exposure have the same functional currency.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Production and manufacturing expenses | (169 | ) | – | | 481 | |
| Finance costs | (17 | ) | (15 | ) | – | |
| Taxation | 44 | | (72 | ) | (144 | ) |
| Profit for the year | 142 | | 87 | | (337 | ) |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Goodwill | 131 | | 131 | |
| Finance debt | (117 | ) | (140 | ) |
| Deferred tax liabilities | 46 | | 46 | |
| BP shareholders’ equity | 202 | | 225 | |
|
|
|
|
|
(f) Inventory valuation
Under IFRS, inventory held for trading purposes is remeasured to fair value with the changes in fair value recognized in the income statement. Under US GAAP, all balances recorded in inventory are measured at the lower of cost and net realizable value.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Purchases | (250 | ) | 357 | | (250 | ) |
| Taxation | 88 | | (125 | ) | 88 | |
| Profit for the year | 162 | | (232 | ) | 162 | |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Inventories | (7 | ) | (257 | ) |
| Deferred tax liabilities | (2 | ) | (90 | ) |
| BP shareholders’ equity | (5 | ) | (167 | ) |
|
|
|
|
|
Back to Contents
53 US GAAP reconciliationcontinued
(g) Gain arising on asset exchange
Under IFRS, exchanges of non-monetary assets are generally accounted for at fair value at the date of the transaction, with any gain or loss recognized in profit or loss. Under US GAAP prior to 1 January 2005, exchanges of non-monetary assets were accounted for at book value. From 1 January 2005 exchanges of non-monetary assets are generally accounted for at fair value under both IFRS and US GAAP.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Depreciation, depletion and amortization | 15 | | 19 | | 117 | |
| Taxation | (5 | ) | (7 | ) | (10 | ) |
| Profit for the year | (10 | ) | (12 | ) | (107 | ) |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Property, plant and equipment | 352 | | 367 | |
| Deferred tax liabilities | 123 | | 128 | |
| BP shareholders’ equity | 229 | | 239 | |
|
|
|
|
|
(h) Pensions and other post-retirement benefits
Under IFRS, the group accounts for its pension and other post-retirement benefit plans according to IAS 19 ‘Employee Benefits’. Surpluses and deficits of pension and other post-retirement benefit plans are included in the group balance sheet at their fair values and all movements in these balances are reflected in the income statement, except for those relating to actuarial gains and losses which are reflected in the statement of recognized income and expense. In the past, this treatment has differed from the group’s US GAAP treatment under SFAS No. 87 ‘Employers’ Accounting for Pensions’ and SFAS No. 106 ‘Employers’ Accounting for Post-retirement Benefits Other Than Pensions’, where actuarial gains and losses were not recognized in the income statement as they occurred but were recognized within income in full only when they exceeded certain thresholds, and otherwise were amortized. This difference in recognition rules for actuarial gains and losses gave rise to differences in periodic pension and other post-retirement benefit expense as measured under IAS 19 compared to SFAS 87 and SFAS 106.
In addition, when a pension plan had an accumulated benefit obligation which exceeded the fair value of the plan assets, SFAS 87 required the unfunded amount to be recognized as a minimum liability in the balance sheet. The offset to this liability was recorded as an intangible asset up to the amount of any unrecognized prior service cost or transitional liability, and thereafter directly in other comprehensive income. IAS 19 does not have a similar concept. As a result, this created a difference in shareholders’ equity as measured under IFRS and US GAAP.
In September 2006, the FASB issued SFAS No. 158 ‘Employers’ Accounting for Defined Benefit Pension and Other Post-retirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)’. SFAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit post-retirement plan (other than a multi-employer plan) as an asset or liability in the balance sheet and to recognize changes in that funded status in other comprehensive income in the year in which the changes occur. Because the funded status of benefit plans is fully recognized in the balance sheet, a minimum liability will no longer be recognized. Retrospective application of SFAS 158 is not permitted. Upon adoption of SFAS 158, the recognition of the overfunded or underfunded status of the group’s defined benefit pension and other post-retirement plans generally accords with the group’s IFRS accounting. Differences in recognition rules for actuarial gains and losses will continue to give rise to differences in periodic pension and other post-retirement benefit expense as measured under IFRS and US GAAP. The group has adopted SFAS 158 with effect from 31 December 2006, resulting in a $599 million decrease in BP shareholders’ equity, as adjusted to accord with US GAAP. Of this total effect, $586 million relates to group entities and $13 million relates to equity-accounted entities. The effect on equity-accounted entities is included in note (j) Equity-accounted investments. Further information on the effects of adoption of SFAS 158 is given below.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Production and manufacturing expenses | 801 | | 583 | | 330 | |
| Other finance (income) expense | 470 | | 116 | | (29 | ) |
| Taxation | (398 | ) | (213 | ) | (254 | ) |
| Profit for the year | (873 | ) | (486 | ) | (47 | ) |
|
|
|
|
|
|
|
| | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Intangible assets | – | | 27 | |
| Other receivables | – | | 6,667 | |
| Defined benefit pension plan surplus | – | | (3,282 | ) |
| Current liabilities | 603 | | – | |
| Provisions | – | | 7,884 | |
| Defined benefit pension plan and other post-retirement benefit plan deficits | (603 | ) | (9,230 | ) |
| Deferred tax liabilities | – | | 1,612 | |
| BP shareholders’ equity | – | | 3,146 | |
|
|
|
|
|
The incremental effects of adopting the provisions of SFAS 158 on the group’s balance sheet at 31 December 2006, as adjusted to accord with US GAAP, are presented in the following table. The adoption of SFAS 158 had no effect on the group’s consolidated income statement, as adjusted to accord with US GAAP, and will not affect the group’s US GAAP profit in future periods. Had the group not been required to adopt SFAS 158 at 31 December 2006, the group would have recognized an additional minimum pension liability. The effect of recognizing the additional minimum pension liability is included in the table below in the column headed ‘Prior to adoption’.
Back to Contents
53 US GAAP reconciliation continued
| | $ million | |
|
|
|
|
|
|
|
| | Prior to | | Effect of | | As | |
| | adoption | | adoption | | reported | |
|
|
|
|
|
|
|
| Intangible assets | 12 | | (12 | ) | – | |
| Other receivables | 7,022 | | (7,022 | ) | – | |
| Defined benefit pension plan surplus | – | | 6,753 | | 6,753 | |
| Current liabilities | – | | 603 | | 603 | |
| Provisions | 8,622 | | (8,622 | ) | – | |
| Defined benefit pension plan and other post-retirement benefit plan deficits | – | | 8,673 | | 8,673 | |
| Deferred tax liabilities | 573 | | (349 | ) | 224 | |
| BP shareholders’ equity | (2,161 | ) | (586 | ) | (2,747 | ) |
|
|
|
|
|
|
|
| Accumulated other comprehensive income | 1,022 | | 935 | | 1,957 | |
| Taxation | 238 | | 349 | | 587 | |
| Accumulated other comprehensive income (net of deferred tax) | 784 | | 586 | | 1,370 | |
|
|
|
|
|
|
|
Further information in respect of the group’s defined benefit pension and other post-retirement plans required under US GAAP is set out below.
| Analysis of the pension and other post-retirement benefits expense | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Defined benefit plans | | | | | | |
| Service cost – benefits earned during year | 829 | | 785 | | 757 | |
| Interest cost on projected benefit obligation | 1,940 | | 2,022 | | 2,012 | |
| Expected return on plan assets | (2,140 | ) | (2,115 | ) | (2,161 | ) |
| Amortization of transition asset | 11 | | 10 | | 9 | |
| Recognized net actuarial (gain) loss | 934 | | 656 | | 445 | |
| Recognized prior service cost | 55 | | 79 | | 64 | |
| Curtailment and settlement (gains) losses | (43 | ) | (38 | ) | (4 | ) |
| Special termination benefits | 278 | | 49 | | 60 | |
|
|
|
|
|
|
|
| | 1,864 | | 1,448 | | 1,182 | |
| Defined contribution plans | 177 | | 172 | | 162 | |
|
|
|
|
|
|
|
| | 2,041 | | 1,620 | | 1,344 | |
| Innovene operations | – | | (83 | ) | (102 | ) |
|
|
|
|
|
|
|
| Total pension and other post-retirement benefits expense for continuing operations | 2,041 | | 1,537 | | 1,242 | |
|
|
|
|
|
|
|
The table below shows the amounts included in accumulated other comprehensive income at 31 December 2006 that have not yet been recognized as components of the pension and other post-retirement benefits expense in the income statement, as adjusted to accord with US GAAP.
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | US other | | | | | |
| | | | | | post- | | | | | |
| | UK | | US | | retirement | | | | | |
| | pension | | pension | | benefit | | Other | | | |
| | plans | | plans | | plans | | plans | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Net actuarial (gain) loss | (1,805 | ) | 2,099 | | 514 | | 1,055 | | 1,863 | |
| Prior service cost (credit) | 398 | | 101 | | (431 | ) | 19 | | 87 | |
| Transition obligation (asset) | – | | – | | – | | 7 | | 7 | |
|
|
|
|
|
|
|
|
|
|
|
| | (1,407 | ) | 2,200 | | 83 | | 1,081 | | 1,957 | |
|
|
|
|
|
|
|
|
|
|
|
The amounts included in accumulated other comprehensive income at 31 December 2006 which are expected to be recognized as components of the pension and other post-retirement benefits expense for the year ended 31 December 2007 in the income statement, as adjusted to accord with US GAAP are shown below.
| | | | | | | | | | $ million | |
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|
|
|
|
|
|
|
|
|
|
| | | | | | US other | | | | | |
| | | | | | post- | | | | | |
| | UK | | US | | retirement | | | | | |
| | pension | | pension | | benefit | | Other | | | |
| | plans | | plans | | plans | | plans | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Net actuarial (gain) loss | 243 | | 222 | | 47 | | 120 | | 632 | |
| Prior service cost (credit) | 76 | | 11 | | (54 | ) | 3 | | 36 | |
| Transition obligation (asset) | – | | – | | – | | – | | – | |
|
|
|
|
|
|
|
|
|
|
|
| | 319 | | 233 | | (7 | ) | 123 | | 668 | |
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|
|
Back to Contents
53 US GAAP reconciliation continued
The table below shows, at 31 December 2006, the aggregate projected benefit obligation and the aggregate fair value of plan assets for those pension plans where the projected benefit obligation exceeds the fair value of the plan assets.
| | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
| | UK | | US | | | | | |
| | pension | | pension | | Other | | | |
| | plans | | plans | | plans | | Total | |
|
|
|
|
|
|
|
|
|
| Projected benefit obligation | 117 | | 411 | | 7,082 | | 7,610 | |
| Fair value of plan assets | – | | 54 | | 1,554 | | 1,608 | |
|
|
|
|
|
|
|
|
|
| Excess of projected benefit obligation over plan assets | 117 | | 357 | | 5,528 | | 6,002 | |
|
|
|
|
|
|
|
|
|
The table below shows, at 31 December 2006, the aggregate accumulated benefit obligation and the aggregate fair value of plan assets for those pension plans where the accumulated benefit obligation exceeds the fair value of the plan assets.
| | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
| | UK | | US | | | | | |
| | pension | | pension | | Other | | | |
| | plans | | plans | | plans | | Total | |
|
|
|
|
|
|
|
|
|
| Accumulated benefit obligation | 92 | | 386 | | 5,770 | | 6,248 | |
| Fair value of plan assets | – | | 54 | | 660 | | 714 | |
|
|
|
|
|
|
|
|
|
| Excess of accumulated benefit obligation over plan assets | 92 | | 332 | | 5,110 | | 5,534 | |
|
|
|
|
|
|
|
|
|
A summary of benefit obligations and amounts recognized under US GAAP in the balance sheet at 31 December 2005 is shown below.
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | US other | | | | | |
| | | | | | post- | | | | | |
| | UK | | US | | retirement | | | | | |
| | pension | | pension | | benefit | | Other | | | |
| | plans | | plans | | plans | | plans | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Benefit obligation at 31 December | 20,063 | | 7,900 | | 3,478 | | 7,414 | | 38,855 | |
| Fair value of plan assets at 31 December | 23,282 | | 7,317 | | 28 | | 2,280 | | 32,907 | |
|
|
|
|
|
|
|
|
|
|
|
| Funded status | 3,219 | | (583 | ) | (3,450 | ) | (5,134 | ) | (5,948 | ) |
| Unrecognized transition (asset) obligation | – | | – | | – | | 17 | | 17 | |
| Unrecognized net actuarial (gain) loss | 222 | | 3,249 | | 793 | | 1,454 | | 5,718 | |
| Unrecognized prior service cost | 490 | | 70 | | (485 | ) | 8 | | 83 | |
|
|
|
|
|
|
|
|
|
|
|
| Net amount recognized | 3,931 | | 2,736 | | (3,142 | ) | (3,655 | ) | (130 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Prepaid benefit cost (accrued benefit liability) | 3,910 | | 2,535 | | (3,154 | ) | (4,508 | ) | (1,217 | ) |
| Intangible asset | – | | 12 | | – | | 15 | | 27 | |
| Accumulated other comprehensive incomea | 21 | | 189 | | 12 | | 838 | | 1,060 | |
|
|
|
|
|
|
|
|
|
|
|
| | 3,931 | | 2,736 | | (3,142 | ) | (3,655 | ) | (130 | ) |
|
|
|
|
|
|
|
|
|
|
|
| a | Total $866 million net of deferred tax. |
(i) Impairments
Under IFRS, in determining the amount of any impairment loss, the carrying value of property, plant and equipment and goodwill is compared with the discounted value of the future cash flows. Under US GAAP, SFAS No. 144 ‘Accounting for the Impairment or Disposal of Long-lived Assets’ requires that the carrying value is compared with the undiscounted future cash flows to determine if an impairment is present, and only if the carrying value is less than the undiscounted cash flows is an impairment loss recognized. The impairment is measured using the discounted value of the future cash flows. Due to this difference, some impairment charges recognized under IFRS, adjusted for the impacts of depreciation, have not been recognized for US GAAP.
Additionally, under IFRS, in certain situations and subject to certain limitations, a previously-recognized impairment loss is reversed. Under US GAAP, the reversal of a previously-recognized impairment loss for an asset to be held and used is not permitted.
The decrease to gain on sale of businesses and fixed assets for the year ended 31 December 2006 represents the impact of a 2005 impairment charge recognized under IFRS but not for US GAAP on certain Gulf of Mexico Shelf assets that were subsequently sold in 2006.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Gain on sale of businesses and fixed assets | (208 | ) | – | | – | |
| Depreciation, depletion and amortization | 6 | | 28 | | – | |
| Impairment and losses on sale of businesses and fixed assets | 340 | | 477 | | (986 | ) |
| Taxation | (222 | ) | (127 | ) | 309 | |
| Profit for the year | (332 | ) | (378 | ) | 677 | |
|
|
|
|
|
|
|
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Property, plant and equipment | (40 | ) | 504 | |
| Deferred tax liabilities | (42 | ) | 177 | |
| BP shareholders’ equity | 2 | | 327 | |
|
|
|
|
|
Back to Contents
53 US GAAP reconciliation continued
(j) Equity-accounted investments
Under IFRS the group’s accounting policies are applied in arriving at the amounts to be included in the financial statements in relation to equity-accounted investments. The major difference between IFRS and US GAAP in this respect relates to deferred tax (see note (a) Deferred taxation/business combinations).
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Earnings from jointly controlled entities | (104 | ) | (255 | ) | 147 | |
| Profit for the year | (104 | ) | (255 | ) | 147 | |
|
|
|
|
|
|
|
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Investments in jointly controlled entities | (160 | ) | (43 | ) |
| BP shareholders’ equity | (160 | ) | (43 | ) |
|
|
|
|
|
(k) Assets classified as held for sale
Recognition and measurement of assets classified as held for sale (and liabilities directly associated with assets classified as held for sale) under IFRS is substantially equivalent to US GAAP. However, the amounts presented for IFRS reporting differ from those under US GAAP due to differences in the underlying carrying values of the assets and liabilities classified as held for sale.
The adjustments to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Goodwill | (10 | ) | – | |
| Assets classified as held for sale | 10 | | – | |
| BP shareholders’ equity | – | | – | |
|
|
|
|
|
(l) Consolidation of variable interest entities
In December 2003, the FASB issued FASB Interpretation No. 46 (Revised) ‘Consolidation of Variable Interest Entities’. Interpretation 46 clarifies the application of existing consolidation requirements to entities where a controlling financial interest is achieved through arrangements that do not involve voting interests. Under Interpretation 46, a variable interest entity is consolidated if a company is subject to a majority of the risk of loss from the variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns.
The group currently has several ships under construction or in service which are accounted for under IFRS as operating leases. Under Interpretation 46 certain of the arrangements represent variable interest entities that would be consolidated by the group. The maximum exposure to loss as a result of the group’s involvement with these entities is limited to the debt of the entity, less the fair value of the ships at the end of the lease term.
During 2006, a number of the existing leasing arrangements that were being consolidated for US GAAP reporting were modified. Under the revised arrangements, the group is not the primary beneficiary. As such, the arrangements are no longer consolidated under US GAAP.
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Production and manufacturing expenses | (18 | ) | (32 | ) | (15 | ) |
| Depreciation, depletion and amortization | 21 | | 23 | | 10 | |
| Finance costs | 6 | | 9 | | 5 | |
| Taxation | (4 | ) | – | | – | |
| Profit for the year | (5 | ) | – | | – | |
|
|
|
|
|
|
|
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Property, plant and equipment | 497 | | 807 | |
| Trade and other payables | (45 | ) | (31 | ) |
| Finance debt | 551 | | 838 | |
| Deferred tax liabilities | (4 | ) | – | |
| BP shareholders’ equity | (5 | ) | – | |
|
|
|
|
|
Back to Contents
53 US GAAP reconciliation continued
(m) Major maintenance expenditure
For the purposes of US GAAP reporting, prior to 1 January 2005, the group capitalized expenditures on maintenance, refits or repairs where it enhanced or restored the performance of an asset, or replaced an asset or part of an asset that was separately depreciated. This included other elements of expenditure incurred during major plant maintenance shutdowns, such as overhaul costs.
With effect from 1 January 2005, the group changed its US GAAP accounting policy to expense the part of major maintenance that represents overhaul costs and similar major maintenance expenditure as incurred. The effect of this accounting change for US GAAP reporting is reflected as a cumulative effect of an accounting change for the year ended 31 December 2005 of $794 million (net of tax benefits of $354 million). This adjustment is equal to the net book value of capitalized overhaul costs as of 1 January 2005 as reported under US GAAP. This new accounting policy reflects the policy applied under IFRS for all periods presented. As a result, a difference between IFRS and US GAAP exists for periods prior to 1 January 2005 which reflects the capitalization of overhaul costs net of the related depreciation charge as calculated under US GAAP.
The adjustments to profit for the year to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Production and manufacturing expenses | – | | – | | (586 | ) |
| Depreciation, depletion and amortization | – | | – | | 296 | |
| Taxation | – | | – | | 73 | |
| Profit for the year before cumulative effect of accounting change | – | | – | | 217 | |
| Cumulative effect of accounting change | – | | (794 | ) | – | |
| Profit for the year | – | | (794 | ) | 217 | |
|
|
|
|
|
|
|
The following pro forma information summarizes the profit for the year assuming the change in accounting for major maintenance expenditure was applied retrospectively with effect from 1 January 2004.
| | | | $ million | |
|
|
|
|
|
| | 2005 | a | 2004 | |
|
|
|
|
|
| Profit for the year attributable to ordinary shares as adjusted to accord with US GAAP | | | | |
| As reported | 19,640 | | 17,088 | |
| Pro forma | 20,434 | | 16,871 | |
| Per ordinary share – cents | | | | |
| Basic – as reported | 92.96 | | 78.31 | |
| Basic – pro forma | 96.72 | | 77.32 | |
| Diluted – as reported | 91.90 | | 76.88 | |
| Diluted – pro forma | 95.61 | | 75.97 | |
| Per American depositary share – cents | | | | |
| Basic – as reported | 557.76 | | 469.86 | |
| Basic – pro forma | 580.32 | | 463.92 | |
| Diluted – as reported | 551.40 | | 461.28 | |
| Diluted – pro forma | 573.66 | | 455.82 | |
|
|
|
|
|
| a | Pro forma data for the year ended 31 December 2005 excludes the cumulative effect of adoption. |
| |
(n) Share-based payments
The group adopted SFAS No. 123 (revised 2004), ‘Share-Based Payment’ with effect from 1 January 2005 using the modified prospective transition method. Under SFAS 123(R), share-based payments to employees are required to be measured based on their grant date fair value (with limited exceptions) and recognized over the related service period. For periods prior to 1 January 2005, the group accounted for share-based payments under Accounting Principles Board Opinion No. 25 using the intrinsic value method.
With effect from 1 January 2005, as part of the adoption of IFRS, the group adopted IFRS 2 ‘Share-based Payment’. IFRS 2 requires the recognition of expense when goods or services are received from employees or others in consideration for equity instruments. In adopting IFRS 2, the group elected to restate prior years to recognize an expense associated with share-based payments that were not fully vested at 1 January 2003, BP’s date of transition to IFRS, and the liability relating to cash-settled share-based payments at 1 January 2003.
As a result of the transition requirements of SFAS 123(R) and IFRS 2, certain differences between US GAAP and IFRS have arisen. For periods prior to 1 January 2005, the group has recognized share-based payments under IFRS using a fair value method which is substantially different from the intrinsic value method used under US GAAP. From 1 January 2005, the group has used the fair value method to measure share-based payment expense under both IFRS and US GAAP. A difference in expense exists however because the group uses a different valuation model under US GAAP for issued options outstanding and not yet vested at 31 December 2004 as required under the transition rules of SFAS 123(R).
In addition, deferred taxes on share-based compensation are recognized differently under US GAAP than under IFRS. Under US GAAP, deferred taxes are recorded on share-based payment expense recognized during the period in accordance with SFAS 109. Under IFRS, deferred taxes are only recorded on the difference between the tax base of the underlying shares and the carrying value of the employee services as determined at each balance sheet date in accordance with IAS 12.
Back to Contents
53 US GAAP reconciliation continued
The adjustments to profit for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.
| Increase (decrease) in caption heading | | | | | $ million | |
|
|
|
|
|
|
|
| | 2006 | | 2005 | | 2004 | |
|
|
|
|
|
|
|
| Production and manufacturing expenses | 5 | | 4 | | (28 | ) |
| Distribution and administration expenses | 9 | | 9 | | (58 | ) |
| Taxation | (106 | ) | (19 | ) | 62 | |
| Profit for the year | 92 | | 6 | | 24 | |
|
|
|
|
|
|
|
| | | | | | | |
| | | | $ million | |
|
|
|
|
|
| | 2006 | | 2005 | |
|
|
|
|
|
| Deferred tax liabilities | 254 | | 334 | |
| BP shareholders’ equity | (254 | ) | (334 | ) |
|
|
|
|
|
(o) Discontinued operations
Under IFRS, a component of an entity held for sale as part of a single plan to dispose of a separate major line of business is classified as a discontinued operation in the income statement.
Under US GAAP (EITF Issue No. 03-13 ‘Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations’), a disposed component of an enterprise is classified as a discontinued operation only where the ongoing entity has no significant continuing direct cash flows and does not retain an interest, contract or other arrangement sufficient to enable the entity to exert significant influence over the disposed component’s operating and financial policies after disposal.
In connection with the sale of Innovene the group has a number of commercial arrangements with Innovene for the supply of refining and petrochemical feedstocks, and the purchase and sale of refined products.
Because of continuing direct cash flows that will result from activities with Innovene subsequent to divestment, under US GAAP the operations of Innovene would not be classified as a discontinued operation but would be included in the group’s continuing operations. Under IFRS, the operations of Innovene are classified as discontinued operations.
The following summarizes the income statement reclassifications that would be made if the operations of Innovene were shown in continuing operations.
| | | | | | $ million | |
|
|
|
|
|
|
|
| | | | | | 2006 | |
|
|
|
|
|
|
|
| | As reported | | Reclassification | | As adjusted | |
|
|
|
|
|
|
|
| Sales and other operating revenues | 265,906 | | – | | 265,906 | |
|
|
|
|
|
|
|
| Profit before interest and taxation from continuing operations | 35,658 | | (184 | ) | 35,474 | |
| Finance costs | 718 | | – | | 718 | |
| Other finance (income) expense | (202 | ) | – | | (202 | ) |
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 35,142 | | (184 | ) | 34,958 | |
| Taxation | 12,516 | | (159 | ) | 12,357 | |
|
|
|
|
|
|
|
| Profit from continuing operations | 22,626 | | (25 | ) | 22,601 | |
| Loss from Innovene operations | (25 | ) | 25 | | – | |
|
|
|
|
|
|
|
| Profit for the year | 22,601 | | – | | 22,601 | |
|
|
|
|
|
|
|
| | | | | | | |
| | | | | | $ million | |
|
|
|
|
|
|
|
| | | | | | 2005 | |
|
|
|
|
|
|
|
| | As reported | | Reclassification | | As adjusted | |
|
|
|
|
|
|
|
| Sales and other operating revenues | 239,792 | | 12,376 | | 252,168 | |
|
|
|
|
|
|
|
| Profit before interest and taxation from continuing operations | 32,182 | | 141 | | 32,323 | |
| Finance costs | 616 | | – | | 616 | |
| Other finance (income) expense | 145 | | (3 | ) | 142 | |
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 31,421 | | 144 | | 31,565 | |
| Taxation | 9,288 | | (40 | ) | 9,248 | |
|
|
|
|
|
|
|
| Profit from continuing operations | 22,133 | | 184 | | 22,317 | |
| Profit from Innovene operations | 184 | | (184 | ) | – | |
|
|
|
|
|
|
|
| Profit for the year | 22,317 | | – | | 22,317 | |
|
|
|
|
|
|
|
Back to Contents
53 US GAAP reconciliationcontinued
| | | | | | $ million | |
|
|
|
|
|
|
|
| | | | | | 2004 | |
|
|
|
|
|
|
|
| | As reported | | Reclassification | | As adjusted | |
|
|
|
|
|
|
|
| Sales and other operating revenues | 192,024 | | 11,279 | | 203,303 | |
|
|
|
|
|
|
|
| Profit before interest and taxation from continuing operations | 25,746 | | (714 | ) | 25,032 | |
| Finance costs | 440 | | – | | 440 | |
| Other finance expense | 340 | | 17 | | 357 | |
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 24,966 | | (731 | ) | 24,235 | |
| Taxation | 7,082 | | (109 | ) | 6,973 | |
|
|
|
|
|
|
|
| Profit from continuing operations | 17,884 | | (622 | ) | 17,262 | |
| Loss from Innovene operations | (622 | ) | 622 | | – | |
|
|
|
|
|
|
|
| Profit for the year | 17,262 | | – | | 17,262 | |
|
|
|
|
|
|
|
| | | | | | | |
(p) Energy trading contracts
The disclosure requirements of EITF 02-03 ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities’, in respect of energy trading contracts are set out below. For the group, energy trading contracts in oil, natural gas, NGLs and power comprise exchange-traded derivative instruments such as futures and options and non-exchange-traded instruments such as swaps, ‘over-the-counter’ options and forward contracts.
The following tables show the net fair value of contracts held for trading purposes at 31 December analysed by maturity period and by methodology of fair value estimation.
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
| | Less than | | | | | | Over | | | |
| | 1 year | | 1-3 years | | 4-5 years | | 5 years | | Total | |
|
|
|
|
|
|
|
|
|
|
|
| Prices actively quoted | – | | – | | – | | – | | – | |
| Prices sourced from observable data or market corroboration | 654 | | 83 | | 55 | | 4 | | 796 | |
| Prices based on models and other valuation methods | 12 | | (26 | ) | (14 | ) | 20 | | (8 | ) |
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| | 666 | | 57 | | 41 | | 24 | | 788 | |
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| | | | | | | | | | | |
| | | | | | | | | | $ million | |
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| | | | | | | | | | 2005 | |
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| | Less than | | | | | | Over | | | |
| | 1 year | | 1-3 years | | 4-5 years | | 5 years | | Total | |
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| Prices actively quoted | (179 | ) | (146 | ) | (4 | ) | (12 | ) | (341 | ) |
| Prices sourced from observable data or market corroboration | 660 | | (89 | ) | 49 | | – | | 620 | |
| Prices based on models and other valuation methods | 12 | | 1 | | 77 | | 46 | | 136 | |
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|
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|
|
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| | 493 | | (234 | ) | 122 | | 34 | | 415 | |
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The following tables show the changes during the year in the net fair value of instruments held for trading purposes for the years 2006, 2005 and 2004.
| | | | | | $ million | |
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| | | | Natural | | | |
| | | | gas | | Power | |
| | Oil price | | price | | price | |
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| Fair value of contracts at 1 January 2006 | (34 | ) | 270 | | 179 | |
| Contracts realized or settled in the year | 83 | | (259 | ) | (33 | ) |
| Unrealized gains (losses) recognized at inception of contract | 36 | | 249 | | (69 | ) |
| Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions | 1 | | – | | – | |
| Other unrealized gains (losses) recognized during the year | (68 | ) | 469 | | (36 | ) |
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| Fair value of contracts at 31 December 2006 | 18 | | 729 | | 41 | |
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| | | | | | | |
| | | | | | $ million | |
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| | | | Natural | | | |
| | | | gas | | Power | |
| | Oil price | | price | | price | |
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| Fair value of contracts at 1 January 2005 | (140 | ) | 414 | | 177 | |
| Contracts realized or settled in the year | 144 | | (681 | ) | 76 | |
| Unrealized gains (losses) recognized at inception of contract | (73 | ) | (41 | ) | 1 | |
| Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions | – | | – | | – | |
| Other unrealized gains (losses) recognized during the year | 35 | | 578 | | (75 | ) |
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| Fair value of contracts at 31 December 2005 | (34 | ) | 270 | | 179 | |
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Back to Contents
53 US GAAP reconciliation continued
| | | | | | $ million | |
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| | | | Natural | | | |
| | | | gas | | Power | |
| | Oil price | | price | | price | |
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| Fair value of contracts at 1 January 2004 | (154 | ) | 191 | | 134 | |
| Contracts realized or settled in the year | 154 | | 259 | | 54 | |
| Unrealized gains (losses) recognized at inception of contract | (33 | ) | 73 | | (3 | ) |
| Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions | – | | – | | – | |
| Other unrealized gains (losses) recognized during the year | (107 | ) | (109 | ) | (8 | ) |
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| Fair value of contracts at 31 December 2004 | (140 | ) | 414 | | 177 | |
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In addition to the risk management activities related to equity crude disposal, refinery supply and marketing, BP’s supply and trading function undertakes trading in the full range of conventional derivative financial and commodity instruments and physical cargoes available in the energy markets. The group controls the scale of the trading exposures by using a value-at-risk model with a maximum value-at-risk limit authorized by the board.
The group measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using value-at-risk techniques. These techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of the end-of-day exposures and the history of one-day price movements, together with the correlation of these price movements. The potential movement in fair values is expressed to 1.65 standard deviations which is equivalent to a 95% confidence level. This means that, in broad terms, one would expect to see an increase or a decrease in fair values greater than the value at risk on approximately one occasion per month if the portfolio were left unchanged.
The group calculates value at risk on all instruments that are held for trading purposes and therefore give an exposure to market risk. The value-at-risk models take account of derivative financial instruments such as oil, natural gas and power price futures and swap agreements. Financial assets and liabilities and physical crude oil and refined products that are treated as held for trading positions are also included in these calculations. For options, a linear approximation is included in the value-at-risk models. The value-at-risk calculation for oil, natural gas, NGLs and power price exposure also includes derivative commodity instruments (commodity contracts that permit settlement either by delivery of the underlying commodity or in cash), such as forward contracts.
The following table shows values at risk for energy trading activities.
| | | | | | | | $ million | |
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| | High | | Low | | Average | | Year end | |
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| 2006 | | | | | | | | |
| Oil price trading | 56 | | 16 | | 29 | | 22 | |
| Natural gas and NGL price trading | 29 | | 10 | | 19 | | 15 | |
| Power price trading | 11 | | 2 | | 6 | | 3 | |
| 2005 | | | | | | | | |
| Oil price trading | 80 | | 17 | | 33 | | 31 | |
| Natural gas and NGL price trading | 39 | | 6 | | 15 | | 17 | |
| Power price trading | 16 | | 2 | | 7 | | 9 | |
| 2004 | | | | | | | | |
| Oil price trading | 30 | | 10 | | 16 | | 25 | |
| Natural gas and NGL price trading | 23 | | 6 | | 13 | | 10 | |
| Power price trading | 10 | | 1 | | 4 | | 4 | |
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Impact of new US accounting standards
Adopted for 2006
Accounting changes and error corrections
In May 2005, the FASB issued SFAS No. 154 ‘Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3’. SFAS 154 applies to all voluntary changes in accounting principle and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior period financial statements of a voluntary change in accounting principle unless it is impracticable. Previously, most voluntary changes in accounting principle were recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 also requires that a change in the method of depreciation, amortization or depletion for long-lived non-financial assets be accounted for as a change in accounting estimate that is affected by a change in accounting principle. Previously, such changes were reported as a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in accounting periods beginning after 15 December 2005. The group adopted SFAS 154 with effect from 1 January 2006. The adoption of SFAS 154 did not have a significant effect on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Back to Contents
53 US GAAP reconciliation continued
Revenue
In September 2005, the FASB ratified the consensus reached by the EITF regarding Issue No. 04-13 ‘Accounting for Purchases and Sales of Inventory with the Same Counterparty’. EITF 04-13 addresses accounting issues that arise when a company both sells inventory to and buys inventory from another entity in the same line of business. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw material, work-in-process or finished goods. At issue is whether the revenue, inventory cost and cost of sales should be recorded at fair value or whether the transactions should be classified as non-monetary transactions. EITF 04-13 requires purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another be combined and recorded as exchanges measured at the book value of the item sold. EITF 04-13 is effective for new arrangements entered into and modifications or renewals of existing arrangements in accounting periods beginning after 15 March 2006. The group adopted EITF 04-13 with effect from 1 January 2006. The adoption of EITF 04-13 did not have a significant effect on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Share-based payments
In February 2006, the FASB issued Staff Position No. FAS 123(R)-4 ‘Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event’. FSP 123(R)-4 clarifies the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. Under FSP 123(R)-4, an option or similar instrument with a contingent cash settlement provision is classified as an equity award provided that the contingent event that permits or requires cash settlement is not considered probable of occurring, the contingent event is not within the control of the employee and the award includes no other features that would require liability classification. For entities that adopted SFAS 123(R) prior to the issuance of FSP 123(R)-4, FSP 123(R)-4 is effective for accounting periods beginning after 3 February 2006. The group adopted FSP 123(R)-4 with effect from 1 January 2006. The adoption of FSP 123(R)-4 did not have a significant effect on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Consolidation of variable interest entities
In April 2006, the FASB issued Staff Position No. FIN 46(R)-6, ‘Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)’. FSP 46(R)-6 clarifies how variability should be considered in applying FIN 46(R). Variability is used in applying FIN 46(R) to determine whether an entity is a variable interest entity, which interests are variable interests in the entity, and who is the primary beneficiary of the variable interest entity. Under FSP 46(R)-6, the variability to be considered in applying FIN 46(R)-6 is based on the design of the entity, the nature and risks of the entity and the purpose for which entity was created. FSP 46(R)-6 is effective for accounting periods beginning after 15 June 2006. The group adopted FSP 46(R)-6 with effect from 1 July 2006. The adoption of FSP 46(R)-6 did not have a significant effect on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Pensions and other post-retirement benefits
In September 2006, the FASB issued SFAS No. 158 ‘Employers’ Accounting for Defined Benefit Pension and Other Post-retirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)’. SFAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit post-retirement plan (other than a multi-employer plan) as an asset or liability in the balance sheet and to recognize changes in that funded status in other comprehensive income in the year in which the changes occur. The group adopted SFAS 158 with effect from 31 December 2006, resulting in a $599 million decrease in BP shareholders’ equity, as adjusted to accord with US GAAP. Of this total effect, $586 million relates to group entities and $13 million relates to equity-accounted entities. Further information on the effects of adoption of SFAS 158 is provided in note (h) Pensions and other post-retirement benefits.
Financial statement misstatements
In September 2006, the staff of the SEC issued Staff Accounting Bulletin No. 108, ‘Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements’. SAB 108 was issued to address the diversity in practice in quantifying misstatements from prior years and assessing their effect on current year financial statements. SAB 108 is effective for fiscal years ending after 15 November 2006. The adoption of SAB 108 did not have a significant effect on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Not yet adopted
Financial instruments
In February 2006, the FASB issued SFAS No. 155, ‘Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140’. SFAS 155 simplifies the accounting for certain hybrid financial instruments under SFAS 133 by permitting fair value remeasurement for financial instruments containing an embedded derivative that otherwise would require separation of the derivative from the financial instrument. SFAS 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring in fiscal years beginning after 15 September 2006. The adoption of SFAS 155 is not expected to have a significant effect on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Taxes collected from customers
In June 2006, the FASB ratified the consensus reached by the EITF regarding Issue No. 06-3 ‘How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)’. Under EITF 06-3, taxes collected from customers and remitted to governmental authorities can be presented either gross within revenue and cost of sales, or net. Where such taxes are significant, EITF 06-3 requires disclosure of the accounting policy for presenting taxes and the amount of any such taxes that are recognized on a gross basis. EITF 06-3 is effective for accounting periods beginning after 15 December 2006. The group has not yet adopted EITF 06-3. The group’s accounting policy with regard to taxes collected from customers and remitted to governmental authorities is to present such taxes net in the income statement, and as a result the adoption of EITF 06-3 will not have any impact.
Back to Contents
53 US GAAP reconciliation continued
Income taxes
In June 2006, the FASB issued FASB Interpretation No. 48 ‘Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109’. Interpretation 48 clarifies the accounting for uncertainty with regard to income taxes recognized in an entity’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the recognition and measurement of a tax position taken or expected to be taken in a tax return. Interpretation 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The group will adopt Interpretation 48 with effect from 1 January 2007. Adoption of Interpretation 48 is not expected to have a significant effect on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Fair value measurements
In September 2006, the FASB issued SFAS No. 157 ‘Fair Value Measurements’. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS 157 is effective for accounting periods beginning after 15 November 2007. The group has not yet completed its evaluation of the impact of adopting SFAS 157 on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
Fair value option
In February 2007, the FASB issued SFAS No. 159 ‘The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115’. SFAS 159 permits an entity, at specified election dates, to choose to measure certain financial instruments and other items at fair value. The objective of SFAS 159 is to provide entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently, without having to apply complex hedge accounting provisions. SFAS 159 is effective for accounting periods beginning after 15 November 2007. The group has not yet completed its evaluation of the impact of adopting SFAS 159 on the group’s profit as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.
54 Auditors’ remuneration for US reporting
| | | | | | | | | | | | $ million | |
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| | | | 2006 | | | | 2005 | | | | 2004 | |
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| Audit fees – Ernst & Young | UK | | Total | | UK | | Total | | UK | | Total | |
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| Group audit | 18 | | 36 | | 15 | | 31 | | 13 | | 27 | |
| Audit-related regulatory reporting | 7 | | 9 | | 3 | | 6 | | 4 | | 7 | |
| Statutory audit of subsidiaries | 6 | | 19 | | 7 | | 23 | | 4 | | 16 | |
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| | 31 | | 64 | | 25 | | 60 | | 21 | | 50 | |
| Innovene operations | – | | – | | (8 | ) | (8 | ) | (2 | ) | (2 | ) |
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| Continuing operations | 31 | | 64 | | 17 | | 52 | | 19 | | 48 | |
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| Fees for other services – Ernst & Young | | | | | | | | | | | | |
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| Further assurance services | | | | | | | | | | | | |
| Acquisition and disposal due diligence | 2 | | 3 | | 2 | | 2 | | 6 | | 7 | |
| Pension plan audits | – | | – | | – | | 1 | | – | | 1 | |
| Other further assurance services | 3 | | 5 | | 16 | | 23 | | 6 | | 9 | |
| Tax services | | | | | | | | | | | | |
| Compliance services | – | | 1 | | 5 | | 10 | | 3 | | 13 | |
| Advisory services | – | | – | | – | | – | | – | | 1 | |
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| | 5 | | 9 | | 23 | | 36 | | 15 | | 31 | |
| Innovene operations | – | | – | | – | | (1 | ) | – | | (1 | ) |
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| Continuing operations | 5 | | 9 | | 23 | | 35 | | 15 | | 30 | |
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Audit fees for 2006 include $5 million of additional fees for 2005 (2005 $4 million of additional fees for 2004). Audit fees are included in the income statement within distribution and administration expenses.
Other further assurance services include $nil (2005 $4 million and 2004 $3 million) in respect of advice on accounting, auditing and financial reporting matters; $nil (2005 $16 million and 2004 $1 million) in respect of internal accounting and risk management control reviews; $5 million (2005 $3 million and 2004 $3 million) in respect of non-statutory audits and $nil (2005 $nil and 2004 $2 million) in respect of project assurance and advice on business and accounting process improvement.
The tax compliance services relate to income tax and indirect tax compliance and employee tax services.
The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements and were pre-approved by the committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young compared to that of other potential service providers. These services are for a fixed term.
Fees paid to major firms of accountants other than Ernst & Young for other services amount to $52 million (2005 $151 million and 2004 $82 million).
Back to Contents
55 Summarized financial information on jointly controlled entities and associates
A summarized statement of income and assets and liabilities based on latest information available, with respect to the group’s equity-accounted jointly controlled entities and associates, is set out below. These figures represent 100% of the income statements and balance sheets of the equity-accounted entities, not BP’s ownership interest.
| | | | | | $ million | |
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| | 2006 | | 2005 | | 2004 | |
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| Sales and other operating revenues | 77,464 | | 61,698 | | 38,842 | |
| Gross profit | 17,745 | | 14,451 | | 9,063 | |
| Profit for the year | 9,113 | | 8,043 | | 5,466 | |
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| | | | $ million | |
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| At 31 December | 2006 | | 2005 | |
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| Non-current assets | 58,086 | | 52,401 | |
| Current assets | 24,153 | | 19,808 | |
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| | 82,239 | | 72,209 | |
| Current liabilities | (17,804 | ) | (15,403 | ) |
| Non-current liabilities | (23,973 | ) | (20,328 | ) |
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| Net assets | 40,462 | | 36,478 | |
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56 Valuation and qualifying accounts
| | | | | | | | | | $ million | |
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| | | | Additions | | | | | |
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| | | | Charged to | | Charged to | | | | | |
| | Balance at | | costs and | | other | | | | Balance at | |
| | 1 January | | expenses | | accountsa | | Deductions | | 31 December | |
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| 2006 | | | | | | | | | | |
| Fixed assets – Investmentsb | 172 | | 26 | | (3 | ) | (44 | ) | 151 | |
| Doubtful debtsb | 374 | | 158 | | 32 | | (143 | ) | 421 | |
| 2005 | | | | | | | | | | |
| Fixed assets – Investmentsb | 168 | | 18 | | (13 | ) | (1 | ) | 172 | |
| Doubtful debtsb | 526 | | 67 | | (30 | ) | (189 | ) | 374 | |
| 2004 | | | | | | | | | | |
| Fixed assets – Investmentsb | 209 | | 12 | | 4 | | (57 | ) | 168 | |
| Doubtful debtsb | 441 | | 254 | | 6 | | (175 | ) | 526 | |
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| a | Principally currency transactions. |
| b | Deducted in the balance sheet from the assets to which they apply. |
57 Computation of ratio of earnings to fixed charges (unaudited)
| | | | | | | | $ million, except ratios | |
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| For the year ended 31 December | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | |
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| Profit before taxationa | 35,142 | | 31,421 | | 24,966 | | 17,731 | | – | |
| Group’s share of income in excess of dividends from equity-accounted entitiesa | – | | (710 | ) | (81 | ) | (666 | ) | – | |
| Capitalized interest, net of amortizationa | (341 | ) | (193 | ) | (133 | ) | (123 | ) | – | |
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| | 34,801 | | 30,518 | | 24,752 | | 16,942 | | – | |
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| Fixed charges | | | | | | | | | | |
| Interest expensea | 718 | | 559 | | 440 | | 482 | | – | |
| Rental expense representative of interesta | 946 | | 605 | | 619 | | 460 | | – | |
| Capitalized interesta | 478 | | 351 | | 204 | | 190 | | – | |
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| | 2,142 | | 1,515 | | 1,263 | | 1,132 | | – | |
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| Total adjusted earnings available for payment of fixed chargesa | 36,943 | | 32,033 | | 26,015 | | 18,074 | | – | |
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| Ratio of earnings to fixed charges | 17.2 | | 21.1 | | 20.6 | | 16.0 | | – | |
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| Fixed charges, as adjusted to accord with US GAAP | 2,142 | | 1,525 | | 1,263 | | 1,132 | | 1,476 | |
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| Total adjusted earnings available for payment of fixed charges, after taking account of adjustments to profit before taxation to accord with US GAAP | 34,856 | | 30,550 | | 23,905 | | 16,760 | | 13,583 | |
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| Ratio of earnings to fixed charges with adjustments to accord with US GAAP | 16.3 | | 20.0 | | 18.9 | | 14.8 | | 9.2 | |
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| |
| a Data for 2006, 2005, 2004 and 2003 has been prepared on the basis of IFRS as adopted for use in the EU. Data for 2002 has not been restated to an IFRS basis. |
58 Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Investments include the investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity income of subsidiaries is the group’s share of operating profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other subsidiaries. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Australia Capital Markets Limited, BP Canada Finance Company, BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of BP p.l.c.
Back to Contents
58 Condensed consolidating information on certain US subsidiaries continued
| Income statement | | | | | | | | | $ million | |
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| For the year ended 31 December | | | | | | | | | 2006 | |
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| | Issuer | | Guarantor | | | | | | | |
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| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
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|
|
|
|
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|
|
|
| Sales and other operating revenues | 4,812 | | – | | 265,906 | | (4,812 | ) | 265,906 | |
| Earnings from jointly controlled entities – after interest and tax | – | | – | | 3,553 | | – | | 3,553 | |
| Earnings from associates – after interest and tax | – | | – | | 442 | | – | | 442 | |
| Equity-accounted income of subsidiaries – after interest and tax | 570 | | 23,119 | | – | | (23,689 | ) | – | |
| Interest and other revenues | 627 | | 187 | | 881 | | (994 | ) | 701 | |
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|
|
|
|
|
|
|
|
|
|
| Total revenues | 6,009 | | 23,306 | | 270,782 | | (29,495 | ) | 270,602 | |
| Gains on sale of businesses and fixed assets | – | | 105 | | 3,714 | | (105 | ) | 3,714 | |
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|
|
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|
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|
|
|
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| Total revenues and other income | 6,009 | | 23,411 | | 274,496 | | (29,600 | ) | 274,316 | |
| Purchases | 566 | | – | | 191,429 | | (4,812 | ) | 187,183 | |
| Production and manufacturing expenses | 814 | | – | | 22,479 | | – | | 23,293 | |
| Production and similar taxes | 665 | | – | | 2,956 | | – | | 3,621 | |
| Depreciation, depletion and amortization | 374 | | – | | 8,754 | | – | | 9,128 | |
| Impairment and losses on sale of businesses and fixed assets | 109 | | – | | 440 | | – | | 549 | |
| Exploration expense | 14 | | – | | 1,031 | | – | | 1,045 | |
| Distribution and administration expenses | 20 | | 278 | | 14,264 | | (115 | ) | 14,447 | |
| Fair value (gain) loss on embedded derivatives | – | | – | | (608 | ) | – | | (608 | ) |
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|
|
|
|
|
|
|
|
|
| Profit before interest and taxation from continuing operations | 3,447 | | 23,133 | | 33,751 | | (24,673 | ) | 35,658 | |
| Finance costs | – | | 702 | | 895 | | (879 | ) | 718 | |
| Other finance expense (income) | 11 | | (675 | ) | 462 | | – | | (202 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 3,436 | | 23,106 | | 32,394 | | (23,794 | ) | 35,142 | |
| Taxation | 1,243 | | 686 | | 10,587 | | – | | 12,516 | |
|
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|
|
|
|
|
|
|
|
|
| Profit from continuing operations | 2,193 | | 22,420 | | 21,807 | | (23,794 | ) | 22,626 | |
| Profit (loss) from Innovene operations | – | | – | | (25 | ) | – | | (25 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year | 2,193 | | 22,420 | | 21,782 | | (23,794 | ) | 22,601 | |
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|
|
|
| Attributable to | | | | | | | | | | |
| BP shareholders | 2,193 | | 22,420 | | 21,496 | | (23,794 | ) | 22,315 | |
| Minority interest | – | | – | | 286 | | – | | 286 | |
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|
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|
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|
|
| | 2,193 | | 22,420 | | 21,782 | | (23,794 | ) | 22,601 | |
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| | | | | | | | | | | |
The following is a summary of the adjustments to the profit for the year attributable to BP shareholders which would be required if US GAAP had been applied instead of IFRS.
| | | | | | | | | | $ million | |
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|
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|
| | | | | | | | | | 2006 | |
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| | Issuer | | Guarantor | | | | | | | |
| |
|
|
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| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
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| Profit as reported | 2,193 | | 22,420 | | 21,496 | | (23,794 | ) | 22,315 | |
| Adjustments | | | | | | | | | | |
| Deferred taxation/business combinations | (33 | ) | (224 | ) | (191 | ) | 224 | | (224 | ) |
| Provisions | 10 | | 177 | | 168 | | (178 | ) | 177 | |
| Oil and natural gas reserves differences | – | | (243 | ) | (243 | ) | 243 | | (243 | ) |
| Goodwill and intangible assets | – | | 13 | | 13 | | (13 | ) | 13 | |
| Derivative financial instruments | – | | 142 | | 142 | | (142 | ) | 142 | |
| Inventory valuation | (5 | ) | 162 | | 162 | | (157 | ) | 162 | |
| Gain arising on asset exchange | (10 | ) | (10 | ) | – | | 10 | | (10 | ) |
| Pensions and other post-retirement benefits | – | | (873 | ) | (389 | ) | 389 | | (873 | ) |
| Impairments | – | | (332 | ) | (332 | ) | 332 | | (332 | ) |
| Equity-accounted investments | – | | (104 | ) | (104 | ) | 104 | | (104 | ) |
| Consolidation of varaible interest entities | – | | (5 | ) | (5 | ) | 5 | | (5 | ) |
| Share-based payments | – | | 92 | | – | | – | | 92 | |
| Other | (8 | ) | 6 | | 14 | | (6 | ) | 6 | |
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| Profit for the year as adjusted to accord with US GAAP | 2,147 | | 21,221 | | 20,731 | | (22,983 | ) | 21,116 | |
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Back to Contents
58 Condensed consolidating information on certain US subsidiariescontinued
| Income statement (continued) | | | | | | | | | | $ million | |
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|
| For the year ended 31 December | | | | | | | | | | 2005 | |
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| | | Issuer | | Guarantor | | | | | | | |
| |
|
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|
|
| | | | | | |
| | | BP | | | | | | Eliminations | | | |
| | | Exploration | | | | Other | | and | | | |
| | | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
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| Sales and other operating revenues | | 5,052 | | – | | 239,792 | | (5,052 | ) | 239,792 | |
| Earnings from jointly controlled entities – after interest and tax | | – | | – | | 3,083 | | – | | 3,083 | |
| Earnings from associates – after interest and tax | | – | | – | | 460 | | – | | 460 | |
| Equity-accounted income of subsidiaries – after interest and tax | | 576 | | 22,255 | | – | | (22,831 | ) | – | |
| Interest and other revenues | | 454 | | 556 | | 749 | | (1,146 | ) | 613 | |
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|
|
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| Total revenues | | 6,082 | | 22,811 | | 244,084 | | (29,029 | ) | 243,948 | |
| Gains on sale of businesses and fixed assets | | 1 | | – | | 1,537 | | – | | 1,538 | |
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|
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|
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| Total revenues and other income | | 6,083 | | 22,811 | | 245,621 | | (29,029 | ) | 245,486 | |
| Purchases | | 729 | | – | | 167,349 | | (5,052 | ) | 163,026 | |
| Production and manufacturing expenses | | 536 | | – | | 21,056 | | – | | 21,592 | |
| Production and similar taxes | | 352 | | – | | 2,658 | | – | | 3,010 | |
| Depreciation, depletion and amortization | | 445 | | – | | 8,326 | | – | | 8,771 | |
| Impairment and losses on sale of businesses and fixed assets | | – | | – | | 468 | | – | | 468 | |
| Exploration expense | | 1 | | – | | 683 | | – | | 684 | |
| Distribution and administration expenses | | 19 | | 629 | | 13,163 | | (105 | ) | 13,706 | |
| Fair value (gain) loss on embedded derivatives | | – | | – | | 2,047 | | – | | 2,047 | |
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|
|
|
|
|
|
|
|
|
| Profit before interest and taxation from continuing operations | | 4,001 | | 22,182 | | 29,871 | | (23,872 | ) | 32,182 | |
| Finance costs | | 169 | | 590 | | 898 | | (1,041 | ) | 616 | |
| Other finance expense (income) | | 14 | | (443 | ) | 574 | | – | | 145 | |
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|
|
|
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| Profit before taxation from continuing operations | | 3,818 | | 22,035 | | 28,399 | | (22,831 | ) | 31,421 | |
| Taxation | | 1,138 | | 9 | | 8,141 | | – | | 9,288 | |
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|
|
| Profit from continuing operations | | 2,680 | | 22,026 | | 20,258 | | (22,831 | ) | 22,133 | |
| Profit (loss) from Innovene operations | | – | | – | | 184 | | – | | 184 | |
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|
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| Profit for the year | | 2,680 | | 22,026 | | 20,442 | | (22,831 | ) | 22,317 | |
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| Attributable to | | | | | | | | | | | |
| BP shareholders | | 2,680 | | 22,026 | | 20,151 | | (22,831 | ) | 22,026 | |
| Minority interest | | – | | – | | 291 | | – | | 291 | |
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|
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| | | 2,680 | | 22,026 | | 20,442 | | (22,831 | ) | 22,317 | |
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|
|
|
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|
|
|
|
|
The following is a summary of the adjustments to the profit for the year attributable to BP shareholders which would be required if US GAAP had been applied instead of IFRS.
| | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
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|
|
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|
| | | | | | | | | | | 2005 | |
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| | | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
|
| | | | | | |
| | | BP | | | | | | Eliminations | | | |
| | | Exploration | | | | Other | | and | | | |
| | | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
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|
| Profit as reported | | 2,680 | | 22,026 | | 20,151 | | (22,831 | ) | 22,026 | |
| Adjustments | | | | | | | | | | | |
| Deferred taxation/business combinations | | (41 | ) | (496 | ) | (455 | ) | 496 | | (496 | ) |
| Provisions | | 5 | | 9 | | 4 | | (9 | ) | 9 | |
| Oil and natural gas reserves differences | | – | | 11 | | 11 | | (11 | ) | 11 | |
| Derivative financial instruments | | – | | 87 | | 87 | | (87 | ) | 87 | |
| Inventory valuation | | (13 | ) | (232 | ) | (232 | ) | 245 | | (232 | ) |
| Gain arising on asset exchange | | (12 | ) | (12 | ) | – | | 12 | | (12 | ) |
| Pensions and other post-retirement benefits | | – | | (486 | ) | (650 | ) | 650 | | (486 | ) |
| Impairments | | – | | (378 | ) | (378 | ) | 378 | | (378 | ) |
| Equity-accounted investments | | – | | (255 | ) | (255 | ) | 255 | | (255 | ) |
| Share-based payments | | – | | 6 | | – | | – | | 6 | |
| Other | | – | | 156 | | 156 | | (156 | ) | 156 | |
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|
Profit for the year before cumulative effect of accounting change as
adjusted to accord with US GAAP | | 2,619 | | 20,436 | | 18,439 | | (21,058 | ) | 20,436 | |
| Cumulative effect of accounting change | | | | | | | | | | | |
| Major maintenance expenditure | | – | | (794 | ) | (794 | ) | 794 | | (794 | ) |
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|
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|
|
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|
|
| Profit for the year as adjusted to accord with US GAAP | | 2,619 | | 19,642 | | 17,645 | | (20,264 | ) | 19,642 | |
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|
Back to Contents
58 Condensed consolidating information on certain US subsidiariescontinued
| Income statement (continued) | | | | | | | | | | $ million | |
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|
|
| For the year ended 31 December | | | | | | | | | | 2004 | |
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|
| | | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
|
| | | | | | |
| | | BP | | | | | | Eliminations | | | |
| | | Exploration | | | | Other | | and | | | |
| | | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
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|
| Sales and other operating revenues | | 3,811 | | – | | 192,024 | | (3,811 | ) | 192,024 | |
| Earnings from jointly controlled entities – after interest and tax | | – | | – | | 1,818 | | – | | 1,818 | |
| Earnings from associates – after interest and tax | | – | | – | | 462 | | – | | 462 | |
| Equity-accounted income of subsidiaries – after interest and tax | | 256 | | 16,951 | | – | | (17,207 | ) | – | |
| Interest and other revenues | | 34 | | 1,466 | | 515 | | (1,400 | ) | 615 | |
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|
| Total revenues | | 4,101 | | 18,417 | | 194,819 | | (22,418 | ) | 194,919 | |
| Gains on sale of businesses and fixed assets | | – | | – | | 1,685 | | – | | 1,685 | |
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| Total revenues and other income | | 4,101 | | 18,417 | | 196,504 | | (22,418 | ) | 196,604 | |
| Purchases | | 506 | | – | | 131,360 | | (3,811 | ) | 128,055 | |
| Production and manufacturing expenses | | 421 | | – | | 16,909 | | – | | 17,330 | |
| Production and similar taxes | | 267 | | – | | 1,882 | | – | | 2,149 | |
| Depreciation, depletion and amortization | | 483 | | – | | 8,046 | | – | | 8,529 | |
| Impairment and losses on sale of businesses and fixed assets | | – | | – | | 1,390 | | – | | 1,390 | |
| Exploration expense | | 4 | | – | | 633 | | – | | 637 | |
| Distribution and administration expenses | | 3 | | 1,472 | | 11,452 | | (159 | ) | 12,768 | |
|
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|
|
|
|
|
|
|
|
| Profit before interest and taxation from continuing operations | | 2,417 | | 16,945 | | 24,832 | | (18,448 | ) | 25,746 | |
| Finance costs | | – | | 274 | | 1,407 | | (1,241 | ) | 440 | |
| Other finance expense (income) | | 15 | | (358 | ) | 683 | | – | | 340 | |
|
|
|
|
|
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | | 2,402 | | 17,029 | | 22,742 | | (17,207 | ) | 24,966 | |
| Taxation | | 552 | | (46 | ) | 6,576 | | – | | 7,082 | |
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|
|
|
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|
|
|
|
|
| Profit from continuing operations | | 1,850 | | 17,075 | | 16,166 | | (17,207 | ) | 17,884 | |
| Profit (loss) from Innovene operations | | – | | – | | (622 | ) | – | | (622 | ) |
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|
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|
|
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|
|
|
| Profit for the year | | 1,850 | | 17,075 | | 15,544 | | (17,207 | ) | 17,262 | |
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|
|
| Attributable to | | | | | | | | | | | |
| BP shareholders | | 1,850 | | 17,075 | | 15,357 | | (17,207 | ) | 17,075 | |
| Minority interest | | – | | – | | 187 | | – | | 187 | |
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|
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|
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|
|
| | | 1,850 | | 17,075 | | 15,544 | | (17,207 | ) | 17,262 | |
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the adjustments to the profit for the year attributable to BP shareholders which would be required if US GAAP had been applied instead of IFRS.
| | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | 2004 | |
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| | | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
|
| | | | | | |
| | | BP | | | | | | Eliminations | | | |
| | | Exploration | | | | Other | | and | | | |
| | | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
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|
|
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|
|
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|
|
|
| Profit as reported | | 1,850 | | 17,075 | | 15,357 | | (17,207 | ) | 17,075 | |
| Adjustments | | | | | | | | | | | |
| Deferred taxation/business combinations | | (10 | ) | (517 | ) | (626 | ) | 636 | | (517 | ) |
| Provisions | | (1 | ) | (80 | ) | (78 | ) | 79 | | (80 | ) |
| Oil and natural gas reserves differences | | – | | 30 | | 30 | | (30 | ) | 30 | |
| Goodwill | | – | | (61 | ) | (61 | ) | 61 | | (61 | ) |
| Derivative financial instruments | | – | | (337 | ) | (337 | ) | 337 | | (337 | ) |
| Inventory valuation | | – | | 162 | | 162 | | (162 | ) | 162 | |
| Gain arising on asset exchange | | (19 | ) | (107 | ) | (88 | ) | 107 | | (107 | ) |
| Pensions and other post-retirement benefits | | – | | (47 | ) | (98 | ) | 98 | | (47 | ) |
| Impairments | | – | | 677 | | 677 | | (677 | ) | 677 | |
| Equity-accounted investments | | – | | 147 | | 147 | | (147 | ) | 147 | |
| Major maintenance expenditure | | – | | 217 | | 217 | | (217 | ) | 217 | |
| Share-based payments | | – | | 24 | | – | | – | | 24 | |
| Other | | – | | (93 | ) | (93 | ) | 93 | | (93 | ) |
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| Profit for the year as adjusted to accord with US GAAP | | 1,820 | | 17,090 | | 15,209 | | (17,029 | ) | 17,090 | |
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|
Back to Contents
58 Condensed consolidating information on certain US subsidiariescontinued
| Balance sheet | | | | | | | | | | $ million | |
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| At 31 December | | | | | | | | | | 2006 | |
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| | | Issuer | | Guarantor | | | | | | | |
| |
|
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|
|
| | | | | | |
| | | BP | | | | | | Eliminations | | | |
| | | Exploration | | | | Other | | and | | | |
| | | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
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| Non-current assets | | | | | | | | | | | |
| Property, plant and equipment | | 5,838 | | – | | 85,161 | | – | | 90,999 | |
| Goodwill | | – | | – | | 10,780 | | – | | 10,780 | |
| Intangible assets | | 309 | | – | | 4,937 | | – | | 5,246 | |
| Investments in jointly controlled entities | | – | | – | | 15,074 | | – | | 15,074 | |
| Investments in associates | | – | | 2 | | 5,973 | | – | | 5,975 | |
| Other investments | | – | | – | | 1,697 | | – | | 1,697 | |
| Subsidiaries – equity-accounted basis | | 2,586 | | 107,717 | | – | | (110,303 | ) | – | |
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| Fixed assets | | 8,733 | | 107,719 | | 123,622 | | (110,303 | ) | 129,771 | |
| Loans | | 1,735 | | 1,196 | | 1,052 | | (3,166 | ) | 817 | |
| Other receivables | | – | | – | | 862 | | – | | 862 | |
| Derivative financial instruments | | – | | – | | 3,025 | | – | | 3,025 | |
| Prepayments and accrued income | | – | | – | | 1,034 | | – | | 1,034 | |
| Defined benefit pension plan surplus | | – | | 5,662 | | 1,091 | | – | | 6,753 | |
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|
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|
| | | 10,468 | | 114,577 | | 130,686 | | (113,469 | ) | 142,262 | |
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|
|
| Current assets | | | | | | | | | | | |
| Loans | | – | | – | | 141 | | – | | 141 | |
| Inventories | | 154 | | – | | 18,761 | | – | | 18,915 | |
| Trade and other receivables | | 15,710 | | 3,074 | | 47,450 | | (27,542 | ) | 38,692 | |
| Derivative financial instruments | | – | | – | | 10,373 | | – | | 10,373 | |
| Prepayments and accrued income | | 15 | | – | | 2,991 | | – | | 3,006 | |
| Current tax receivable | | – | | – | | 544 | | – | | 544 | |
| Cash and cash equivalents | | (5 | ) | (21 | ) | 2,616 | | – | | 2,590 | |
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|
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|
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|
|
|
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|
|
| | | 15,874 | | 3,053 | | 82,876 | | (27,542 | ) | 74,261 | |
| Assets classified as held for sale | | – | | – | | 1,078 | | – | | 1,078 | |
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|
|
|
|
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|
|
|
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|
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| | | 15,874 | | 3,053 | | 83,954 | | (27,542 | ) | 75,339 | |
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets | | 26,342 | | 117,630 | | 214,640 | | (141,011 | ) | 217,601 | |
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|
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|
|
|
|
| Current liabilities | | | | | | | | | | | |
| Trade and other payables | | 4,908 | | 5,185 | | 59,685 | | (27,542 | ) | 42,236 | |
| Derivative financial instruments | | – | | – | | 9,424 | | – | | 9,424 | |
| Accruals and deferred income | | – | | 10 | | 6,137 | | – | | 6,147 | |
| Finance debt | | 55 | | – | | 12,869 | | – | | 12,924 | |
| Current tax payable | | 1,705 | | – | | 930 | | – | | 2,635 | |
| Provisions | | – | | – | | 1,932 | | – | | 1,932 | |
|
|
|
|
|
|
|
|
|
|
|
|
| | | 6,668 | | 5,195 | | 90,977 | | (27,542 | ) | 75,298 | |
| Liabilities directly associated with assets classified as held for sale | | – | | – | | 54 | | – | | 54 | |
|
|
|
|
|
|
|
|
|
|
|
|
| | | 6,668 | | 5,195 | | 91,031 | | (27,542 | ) | 75,352 | |
|
|
|
|
|
|
|
|
|
|
|
|
| Non-current liabilities | | | | | | | | | | | |
| Other payables | | 249 | | 27 | | 4,320 | | (3,166 | ) | 1,430 | |
| Derivative financial instruments | | – | | – | | 4,203 | | – | | 4,203 | |
| Accruals and deferred income | | – | | 30 | | 931 | | – | | 961 | |
| Finance debt | | – | | – | | 11,086 | | – | | 11,086 | |
| Deferred tax liabilities | | 1,780 | | 1,506 | | 14,830 | | – | | 18,116 | |
| Provisions | | 640 | | – | | 11,072 | | – | | 11,712 | |
Defined benefit pension plan and other post-retirement benefit plan
deficits | | – | | – | | 9,276 | | – | | 9,276 | |
|
|
|
|
|
|
|
|
|
|
|
|
| | | 2,669 | | 1,563 | | 55,718 | | (3,166 | ) | 56,784 | |
|
|
|
|
|
|
|
|
|
|
|
|
| Total liabilities | | 9,337 | | 6,758 | | 146,749 | | (30,708 | ) | 132,136 | |
|
|
|
|
|
|
|
|
|
|
|
|
| Net assets | | 17,005 | | 110,872 | | 67,891 | | (110,303 | ) | 85,465 | |
|
|
|
|
|
|
|
|
|
|
|
|
| Equity | | | | | | | | | | | |
| BP shareholders’ equity | | 17,005 | | 110,872 | | 67,050 | | (110,303 | ) | 84,624 | |
| Minority interest | | – | | – | | 841 | | – | | 841 | |
|
|
|
|
|
|
|
|
|
|
|
|
| Total equity | | 17,005 | | 110,872 | | 67,891 | | (110,303 | ) | 85,465 | |
|
|
|
|
|
|
|
|
|
|
|
|
Back to Contents
58 Condensed consolidating information on certain US subsidiariescontinued
| Balance sheet (continued) | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
| At 31 December | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
|
| | | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
|
| | | | | | |
| | | BP | | | | | | Eliminations | | | |
| | | Exploration | | | | Other | | and | | | |
| | | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
|
| Capital and reserves | | | | | | | | | | | |
| Capital shares | | 3,353 | | 5,385 | | – | | (3,353 | ) | 5,385 | |
| Paid-in surplus | | 3,145 | | 9,913 | | – | | (3,145 | ) | 9,913 | |
| Merger reserve | | – | | 26,504 | | 697 | | – | | 27,201 | |
| Other reserves | | – | | 5 | | – | | – | | 5 | |
| Shares held by ESOP trusts | | – | | (154 | ) | – | | – | | (154 | ) |
| Available-for-sale investments | | – | | – | | 386 | | – | | 386 | |
| Cash flow hedges | | – | | – | | 39 | | – | | 39 | |
| Foreign currency translation reserve | | – | | – | | 4,685 | | – | | 4,685 | |
| Treasury shares | | – | | (22,182 | ) | – | | – | | (22,182 | ) |
| Shared-based payments | | – | | 859 | | – | | – | | 859 | |
| Retained earnings | | 10,507 | | 90,542 | | 61,243 | | (103,805 | ) | 58,487 | |
|
|
|
|
|
|
|
|
|
|
|
|
| | | 17,005 | | 110,872 | | 67,050 | | (110,303 | ) | 84,624 | |
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the adjustments to BP shareholders’ equity which would be required if US GAAP had been applied instead of IFRS.
| | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
| At 31 December | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
|
| | | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
|
| | | | | | |
| | | BP | | | | | | Eliminations | | | |
| | | Exploration | | | | Other | | and | | | |
| | | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
|
| BP shareholders’ equity as reported | | 17,005 | | 110,872 | | 67,050 | | (110,303 | ) | 84,624 | |
| Adjustments | | | | | | | | | | | |
| Deferred taxation/business combinations | | 182 | | 1,801 | | 1,619 | | (1,801 | ) | 1,801 | |
| Provisions | | 41 | | 63 | | 25 | | (66 | ) | 63 | |
| Oil and natural gas reserves differences | | – | | (202 | ) | (202 | ) | 202 | | (202 | ) |
| Goodwill and intangible assets | | – | | 248 | | 248 | | (248 | ) | 248 | |
| Derivative financial instruments | | – | | 202 | | 202 | | (202 | ) | 202 | |
| Inventory valuation | | (81 | ) | (5 | ) | (5 | ) | 86 | | (5 | ) |
| Gain arising on asset exchange | | 229 | | 229 | | – | | (229 | ) | 229 | |
| Impairments | | – | | 2 | | 2 | | (2 | ) | 2 | |
| Equity-accounted investments | | – | | (160 | ) | (160 | ) | 160 | | (160 | ) |
| Consolidation of variable interest entities | | – | | (5 | ) | (5 | ) | 5 | | (5 | ) |
| Share-based payments | | – | | (254 | ) | – | | – | | (254 | ) |
| Other | | (8 | ) | (26 | ) | (18 | ) | 26 | | (26 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
| BP shareholders’ equity as adjusted to accord with US GAAP | | 17,368 | | 112,765 | | 68,756 | | (112,372 | ) | 86,517 | |
|
|
|
|
|
|
|
|
|
|
|
|
Back to Contents
58 Condensed consolidating information on certain US subsidiaries continued
| Balance sheet (continued) | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| At 31 December | | | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| Non-current assets | | | | | | | | | | |
| Property, plant and equipment | 5,852 | | – | | 80,095 | | – | | 85,947 | |
| Goodwill | – | | – | | 10,371 | | – | | 10,371 | |
| Intangible assets | 418 | | – | | 4,354 | | – | | 4,772 | |
| Investments in jointly controlled entities | – | | – | | 13,556 | | – | | 13,556 | |
| Investments in associates | – | | 2 | | 6,215 | | – | | 6,217 | |
| Other investments | – | | – | | 967 | | – | | 967 | |
| Subsidiaries – equity-accounted basis | 2,016 | | 107,206 | | – | | (109,222 | ) | – | |
|
|
|
|
|
|
|
|
|
|
|
| Fixed assets | 8,286 | | 107,208 | | 115,558 | | (109,222 | ) | 121,830 | |
| Loans | 1,800 | | 1,434 | | (119 | ) | (2,294 | ) | 821 | |
| Other receivables | – | | – | | 770 | | – | | 770 | |
| Derivative financial instruments | – | | – | | 3,909 | | – | | 3,909 | |
| Prepayments and accrued income | – | | – | | 1,012 | | – | | 1,012 | |
| Defined benefit pension plan surplus | – | | 3,226 | | 56 | | – | | 3,282 | |
|
|
|
|
|
|
|
|
|
|
|
| | 10,086 | | 111,868 | | 121,186 | | (111,516 | ) | 131,624 | |
|
|
|
|
|
|
|
|
|
|
|
| Current assets | | | | | | | | | | |
| Loans | – | | – | | 132 | | – | | 132 | |
| Inventories | 128 | | – | | 19,632 | | – | | 19,760 | |
| Trade and other receivables | 13,780 | | 1,211 | | 50,313 | | (24,402 | ) | 40,902 | |
| Derivative financial instruments | – | | – | | 10,056 | | – | | 10,056 | |
| Prepayments and accrued income | 9 | | – | | 1,259 | | – | | 1,268 | |
| Current tax receivable | – | | – | | 212 | | – | | 212 | |
| Cash and cash equivalents | (7 | ) | 3 | | 2,964 | | – | | 2,960 | |
|
|
|
|
|
|
|
|
|
|
|
| | 13,910 | | 1,214 | | 84,568 | | (24,402 | ) | 75,290 | |
|
|
|
|
|
|
|
|
|
|
|
| Total assets | 23,996 | | 113,082 | | 205,754 | | (135,918 | ) | 206,914 | |
|
|
|
|
|
|
|
|
|
|
|
| Current liabilities | | | | | | | | | | |
| Trade and other payables | 4,512 | | 6,719 | | 55,307 | | (24,402 | ) | 42,136 | |
| Derivative financial instruments | – | | – | | 10,036 | | – | | 10,036 | |
| Accruals and deferred income | – | | – | | 5,017 | | – | | 5,017 | |
| Finance debt | 55 | | – | | 8,877 | | – | | 8,932 | |
| Current tax payable | 1,537 | | – | | 2,737 | | – | | 4,274 | |
| Provisions | – | | – | | 1,602 | | – | | 1,602 | |
|
|
|
|
|
|
|
|
|
|
|
| | 6,104 | | 6,719 | | 83,576 | | (24,402 | ) | 71,997 | |
|
|
|
|
|
|
|
|
|
|
|
| Non-current liabilities | | | | | | | | | | |
| Other payables | 495 | | – | | 3,734 | | (2,294 | ) | 1,935 | |
| Derivative financial instruments | – | | – | | 5,871 | | – | | 5,871 | |
| Accruals and deferred income | – | | 27 | | 962 | | – | | 989 | |
| Finance debt | – | | – | | 10,230 | | – | | 10,230 | |
| Deferred tax liabilities | 1,816 | | 532 | | 13,910 | | – | | 16,258 | |
| Provisions | 536 | | – | | 9,418 | | – | | 9,954 | |
| Defined benefit pension plan and other post-retirement benefit plan deficits | 82 | | – | | 9,148 | | – | | 9,230 | |
|
|
|
|
|
|
|
|
|
|
|
| | 2,929 | | 559 | | 53,273 | | (2,294 | ) | 54,467 | |
|
|
|
|
|
|
|
|
|
|
|
| Total liabilities | 9,033 | | 7,278 | | 136,849 | | (26,696 | ) | 126,464 | |
|
|
|
|
|
|
|
|
|
|
|
| Net assets | 14,963 | | 105,804 | | 68,905 | | (109,222 | ) | 80,450 | |
|
|
|
|
|
|
|
|
|
|
|
| Equity | | | | | | | | | | |
| BP shareholders’ equity | 14,963 | | 105,804 | | 68,116 | | (109,222 | ) | 79,661 | |
| Minority interest | – | | – | | 789 | | – | | 789 | |
|
|
|
|
|
|
|
|
|
|
|
| Total equity | 14,963 | | 105,804 | | 68,905 | | (109,222 | ) | 80,450 | |
|
|
|
|
|
|
|
|
|
|
|
Back to Contents
58 Condensed consolidating information on certain US subsidiaries continued
| Balance sheet (continued) | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| At 31 December | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| Capital and reserves | | | | | | | | | | |
| Capital shares | 3,353 | | 5,185 | | – | | (3,353 | ) | 5,185 | |
| Paid-in surplus | 3,145 | | 8,120 | | – | | (3,145 | ) | 8,120 | |
| Merger reserve | – | | 26,493 | | 697 | | – | | 27,190 | |
| Other reserves | – | | 16 | | – | | – | | 16 | |
| Shares held by ESOP trusts | – | | (140 | ) | – | | – | | (140 | ) |
| Available-for-sale investments | – | | – | | 385 | | – | | 385 | |
| Cash flow hedges | – | | – | | (234 | ) | – | | (234 | ) |
| Foreign currency translation reserve | – | | – | | 2,943 | | – | | 2,943 | |
| Treasury shares | – | | (10,598 | ) | – | | – | | (10,598 | ) |
| Share-based payments | – | | 665 | | – | | – | | 665 | |
| Retained earnings | 8,465 | | 76,063 | | 64,325 | | (102,724 | ) | 46,129 | |
|
|
|
|
|
|
|
|
|
|
|
| | 14,963 | | 105,804 | | 68,116 | | (109,222 | ) | 79,661 | |
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the adjustments to BP shareholders’ equity which would be required if US GAAP had been applied instead of IFRS.
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| At 31 December | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| BP shareholders’ equity as reported | 14,963 | | 105,804 | | 68,116 | | (109,222 | ) | 79,661 | |
| Adjustments | | | | | | | | | | |
| Deferred taxation/business combinations | 215 | | 2,025 | | 1,810 | | (2,025 | ) | 2,025 | |
| Provisions | 31 | | (112 | ) | (141 | ) | 110 | | (112 | ) |
| Oil and natural gas reserves differences | – | | 41 | | 41 | | (41 | ) | 41 | |
| Goodwill and intangible assets | – | | 171 | | 171 | | (171 | ) | 171 | |
| Derivative financial instruments | – | | 225 | | 225 | | (225 | ) | 225 | |
| Inventory valuation | (76 | ) | (167 | ) | (167 | ) | 243 | | (167 | ) |
| Gain arising on asset exchange | 239 | | 239 | | – | | (239 | ) | 239 | |
| Pensions and other post-retirement benefits | 82 | | 3,146 | | 2,570 | | (2,652 | ) | 3,146 | |
| Impairments | – | | 327 | | 327 | | (327 | ) | 327 | |
| Equity-accounted investments | – | | (43 | ) | (43 | ) | 43 | | (43 | ) |
| Share-based payments | – | | (334 | ) | – | | – | | (334 | ) |
| Other | – | | (32 | ) | (32 | ) | 32 | | (32 | ) |
|
|
|
|
|
|
|
|
|
|
|
| BP shareholders’ equity as adjusted to accord with US GAAP | 15,454 | | 111,290 | | 72,877 | | (114,474 | ) | 85,147 | |
|
|
|
|
|
|
|
|
|
|
|
Back to Contents
58 Condensed consolidating information on certain US subsidiaries continued
| Cash flow statement | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities | 3,522 | | 20,628 | | 29,030 | | (25,008 | ) | 28,172 | |
| Net cash used in investing activities | (379 | ) | 843 | | (9,982 | ) | – | | (9,518 | ) |
| Net cash used in financing activities | (3,141 | ) | (21,495 | ) | (19,443 | ) | 25,008 | | (19,071 | ) |
| Currency translation differences relating to cash and cash equivalents | – | | – | | 47 | | – | | 47 | |
|
|
|
|
|
|
|
|
|
|
|
| (Decrease) increase in cash and cash equivalents | 2 | | (24 | ) | (348 | ) | – | | (370 | ) |
| Cash and cash equivalents at beginning of year | (7 | ) | 3 | | 2,964 | | – | | 2,960 | |
|
|
|
|
|
|
|
|
|
|
|
| Cash and cash equivalents at end of year | (5 | ) | (21 | ) | 2,616 | | – | | 2,590 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | |
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2005 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities of continuing operations | 3,558 | | 19,835 | | 23,592 | | (21,234 | ) | 25,751 | |
| Net cash provided by (used in) operating activities of Innovene operations | – | | – | | 970 | | – | | 970 | �� |
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities | 3,558 | | 19,835 | | 24,562 | | (21,234 | ) | 26,721 | |
| Net cash used in investing activities | (346 | ) | (2,410 | ) | 1,027 | | – | | (1,729 | ) |
| Net cash used in financing activities | (3,218 | ) | (17,426 | ) | (23,893 | ) | 21,234 | | (23,303 | ) |
| Currency translation differences relating to cash and cash equivalents | – | | – | | (88 | ) | – | | (88 | ) |
|
|
|
|
|
|
|
|
|
|
|
| (Decrease) increase in cash and cash equivalents | (6 | ) | (1 | ) | 1,608 | | – | | 1,601 | |
| Cash and cash equivalents at beginning of year | (1 | ) | 4 | | 1,356 | | – | | 1,359 | |
|
|
|
|
|
|
|
|
|
|
|
| Cash and cash equivalents at end of year | (7 | ) | 3 | | 2,964 | | – | | 2,960 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | |
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2004 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities of continuing operations | 2,467 | | 44,767 | | (4,621 | ) | (18,566 | ) | 24,047 | |
| Net cash provided by (used in) operating activities of Innovene operations | – | | – | | (669 | ) | – | | (669 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities | 2,467 | | 44,767 | | (5,290 | ) | (18,566 | ) | 23,378 | |
| Net cash used in investing activities | (364 | ) | (31,517 | ) | 20,758 | | (208 | ) | (11,331 | ) |
| Net cash used in financing activities | (2,099 | ) | (13,249 | ) | (16,261 | ) | 18,774 | | (12,835 | ) |
| Currency translation differences relating to cash and cash equivalents | – | | – | | 91 | | – | | 91 | |
|
|
|
|
|
|
|
|
|
|
|
| (Decrease) increase in cash and cash equivalents | 4 | | 1 | | (702 | ) | – | | (697 | ) |
| Cash and cash equivalents at beginning of year | (5 | ) | 3 | | 2,058 | | – | | 2,056 | |
|
|
|
|
|
|
|
|
|
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|
| Cash and cash equivalents at end of year | (1 | ) | 4 | | 1,356 | | – | | 1,359 | |
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Back to Contents
Supplementary information on oil and natural gas (unaudited)
Movements in estimated net proved reserves
For details of BP’s governance process for the booking of oil and natural gas reserves, see page 13.
| | | | | | | | | | | | | | | | | | 2006 | |
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| Crude oila | | | | | | | | | | | | | | | million barrels | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2006 | | | | | | | | | | | | | | | | | | |
| Developed | 496 | | 225 | | 1,984 | | 215 | | 70 | | 142 | | – | | 69 | | 3,201 | |
| Undeveloped | 184 | | 86 | | 1,429 | | 286 | | 95 | | 536 | | – | | 543 | | 3,159 | |
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| | 680 | | 311 | | 3,413 | | 501 | | 165 | | 678 | | – | | 612 | | 6,360 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | (3 | ) | (11 | ) | (108 | ) | (9 | ) | – | | 2 | | – | | 16 | | (113 | ) |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Extensions, discoveries and other additions | 3 | | – | | 48 | | – | | 1 | | 67 | | – | | – | | 119 | |
| Improved recovery | 26 | | 9 | | 95 | | 13 | | 4 | | 22 | | – | | – | | 169 | |
| Productionb | (92 | ) | (23 | ) | (178 | ) | (39 | ) | (17 | ) | (64 | ) | – | | (58 | ) | (471 | ) |
| Sales of reserves-in-place | (10 | ) | – | | (62 | ) | (99 | ) | – | | – | | – | | – | | (171 | ) |
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| | (76 | ) | (25 | ) | (205 | ) | (134 | ) | (12 | ) | 27 | | – | | (42 | ) | (467 | ) |
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| At 31 December 2006c | | | | | | | | | | | | | | | | | | |
| Developed | 458 | | 189 | | 1,916 | | 130 | | 67 | | 193 | | – | | 88 | | 3,041 | |
| Undeveloped | 146 | | 97 | | 1,292 | | 237 | | 86 | | 512 | | – | | 482 | | 2,852 | |
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| | 604 | | 286 | | 3,208 | e | 367 | | 153 | | 705 | | – | | 570 | | 5,893 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
| At 1 January 2006 | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 207 | | 1 | | – | | 1,688 | | 590 | | 2,486 | |
| Undeveloped | – | | – | | | | 124 | | – | | – | | 431 | | 164 | | 719 | |
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| | – | | – | | – | | 331 | | 1 | | – | | 2,119 | | 754 | | 3,205 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | – | | – | | – | | (2 | ) | – | | – | | 1,215 | | (8 | ) | 1,205 | |
| Purchases of reserves-in-place | – | | – | | – | | 28 | | – | | – | | – | | – | | 28 | |
| Extensions, discoveries and other additions | – | | – | | – | | 1 | | – | | – | | – | | – | | 1 | |
| Improved recovery | – | | – | | – | | 34 | | – | | – | | – | | – | | 34 | |
| Production | – | | – | | – | | (28 | ) | – | | – | | (320 | ) | (63 | ) | (411 | ) |
| Sales of reserves-in-place | – | | – | | – | | (4 | ) | – | | – | | (170 | ) | – | | (174 | ) |
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| | – | | – | | – | | 29 | | – | | – | | 725 | | (71 | ) | 683 | |
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| At 31 December 2006d | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 221 | | 1 | | – | | 2,200 | | 520 | | 2,942 | |
| Undeveloped | – | | – | | – | | 139 | | – | | – | | 644 | | 163 | | 946 | |
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| | – | | – | | – | | 360 | | 1 | | – | | 2,844 | | 683 | | 3,888 | |
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| a | Crude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind. |
| b | Excludes NGLs from processing plants in which an interest is held of 55 thousand barrels a day. |
| c | Includes 779 million barrels of NGLs. Also includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | Includes 28 million barrels of NGLs. Also includes 179 million barrels of crude oil in respect of the 6.29% minority interest in TNK-BP. |
| e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 81 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
Back to Contents
Supplementary information on oil and natural gas (unaudited) continued
| Movements in estimated net proved reserves | | | | | | | | | | | | | | | | 2006 | |
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| Natural gasa | | | | | | | | | | | | | | | billion cubic feet | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2006 | | | | | | | | | | | | | | | | | | |
| Developed | 2,382 | | 245 | | 11,184 | | 3,560 | | 1,459 | | 934 | | – | | 281 | | 20,045 | |
| Undeveloped | 904 | | 80 | | 4,198 | | 10,504 | | 5,375 | | 2,000 | | – | | 1,342 | | 24,403 | |
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| | 3,286 | | 325 | | 15,382 | | 14,064 | | 6,834 | | 2,934 | | – | | 1,623 | | 44,448 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | (343 | ) | 11 | | (922 | ) | (291 | ) | (92 | ) | (69 | ) | – | | 33 | | (1,673 | ) |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Extensions, discoveries and other additions | 101 | | – | | 116 | | – | | 21 | | 5 | | – | | 2 | | 245 | |
| Improved recovery | 144 | | – | | 1,755 | | 344 | | 71 | | 6 | | – | | 9 | | 2,329 | |
| Productionb | (370 | ) | (38 | ) | (941 | ) | (982 | ) | (273 | ) | (169 | ) | – | | (82 | ) | (2,855 | ) |
| Sales of reserves-in-place | (25 | ) | – | | (292 | ) | (9 | ) | – | | – | | – | | – | | (326 | ) |
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| | (493 | ) | (27 | ) | (284 | ) | (938 | ) | (273 | ) | (227 | ) | – | | (38 | ) | (2,280 | ) |
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| At 31 December 2006c | | | | | | | | | | | | | | | | | | |
| Developed | 1,968 | | 242 | | 10,438 | | 3,932 | | 1,359 | | 1,032 | | – | | 331 | | 19,302 | |
| Undeveloped | 825 | | 56 | | 4,660 | | 9,194 | | 5,202 | | 1,675 | | – | | 1,254 | | 22,866 | |
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| | 2,793 | | 298 | | 15,098 | | 13,126 | | 6,561 | | 2,707 | | – | | 1,585 | | 42,168 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
| At 1 January 2006 | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 1,492 | | 50 | | – | | 1,089 | | 130 | | 2,761 | |
| Undeveloped | – | | – | | – | | 848 | | 26 | | – | | 169 | | 52 | | 1,095 | |
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| | – | | – | | – | | 2,340 | | 76 | | – | | 1,258 | | 182 | | 3,856 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | – | | – | | – | | 7 | | 13 | | – | | 217 | | 47 | | 284 | |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Extensions, discoveries and other additions | – | | – | | – | | 23 | | – | | – | | – | | – | | 23 | |
| Improved recovery | – | | – | | – | | 73 | | 1 | | – | | – | | – | | 74 | |
| Productionb | – | | – | | – | | (171 | ) | (15 | ) | – | | (204 | ) | (7 | ) | (397 | ) |
| Sales of reserves-in-place | – | | – | | – | | (77 | ) | – | | – | | – | | – | | (77 | ) |
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| | – | | – | | – | | (145 | ) | (1 | ) | – | | 13 | | 40 | | (93 | ) |
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| At 31 December 2006d | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 1,460 | | 52 | | – | | 1,087 | | 170 | | 2,769 | |
| Undeveloped | – | | – | | – | | 735 | | 23 | | – | | 184 | | 52 | | 994 | |
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| | – | | – | | – | | 2,195 | | 75 | | – | | 1,271 | | 222 | | 3,763 | |
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| a | Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind. |
| b | Includes 178 billion cubic feet of natural gas consumed in operations, 147 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities and excludes 8.3 billion cubic feet of produced non-hydrocarbon components which meet regulatory requirements for sales. |
| c | Includes 3,537 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | Includes 99 billion cubic feet of natural gas in respect of the 7.77% minority interest in TNK-BP. |
Back to Contents
Supplementary information on oil and natural gas (unaudited)continued
| Movements in estimated net proved reserves | | | | | | | | | | | | | | | | 2005 | |
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| Crude oila | | | | | | | | | | | | | | | | | million barrels | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2005 | | | | | | | | | | | | | | | | | | |
| Developed | 559 | | 231 | | 2,041 | | 311 | | 65 | | 204 | | – | | 62 | | 3,473 | |
| Undeveloped | 210 | | 109 | | 1,211 | | 299 | | 85 | | 643 | | – | | 725 | | 3,282 | |
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| | 769 | | 340 | | 3,252 | | 610 | | 150 | | 847 | | – | | 787 | | 6,755 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | (31 | ) | (8 | ) | 103 | | (21 | ) | 21 | | (190 | ) | – | | (148 | ) | (274 | ) |
| Purchases of reserves-in-place | – | | – | | 2 | | – | | – | | – | | – | | – | | 2 | |
| Extensions, discoveries and other additions | 11 | | – | | 40 | | 3 | | 11 | | 83 | | – | | – | | 148 | |
| Improved recovery | 32 | | 21 | | 217 | | 1 | | – | | 2 | | – | | 7 | | 280 | |
| Productionb | (101 | ) | (27 | ) | (200 | ) | (53 | ) | (17 | ) | (64 | ) | – | | (34 | ) | (496 | ) |
| Sales of reserves-in-place | – | | (15 | ) | (1 | ) | (39 | ) | – | | – | | – | | – | | (55 | ) |
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| | (89 | ) | (29 | ) | 161 | | (109 | ) | 15 | | (169 | ) | – | | (175 | ) | (395 | ) |
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| At 31 December 2005c | | | | | | | | | | | | | | | | | | |
| Developed | 496 | | 225 | | 1,984 | | 215 | | 70 | | 142 | | – | | 69 | | 3,201 | |
| Undeveloped | 184 | | 86 | | 1,429 | | 286 | | 95 | | 536 | | – | | 543 | | 3,159 | |
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| | 680 | | 311 | | 3,413 | e | 501 | | 165 | | 678 | | – | | 612 | | 6,360 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
| At 1 January 2005 | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 204 | | 1 | | – | | 1,863 | | 592 | | 2,660 | |
| Undeveloped | – | | – | | – | | 125 | | – | | – | | 294 | | 100 | | 519 | |
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| | – | | – | | – | | 329 | | 1 | | – | | 2,157 | | 692 | | 3,179 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | – | | – | | – | | 1 | | – | | – | | 319 | | 119 | | 439 | |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Extensions, discoveries and other additions | – | | – | | – | | 2 | | – | | – | | – | | – | | 2 | |
| Improved recovery | – | | – | | – | | 25 | | – | | – | | – | | – | | 25 | |
| Production | – | | – | | – | | (26 | ) | – | | – | | (333 | ) | (57 | ) | (416 | ) |
| Sales of reserves-in-place | – | | – | | – | | – | | – | | – | | (24 | ) | – | | (24 | ) |
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| | – | | – | | – | | 2 | | – | | – | | (38 | ) | 62 | | 26 | |
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| At 31 December 2005d | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 207 | | 1 | | – | | 1,688 | | 590 | | 2,486 | |
| Undeveloped | – | | – | | – | | 124 | | – | | – | | 431 | | 164 | | 719 | |
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| | – | | – | | – | | 331 | | 1 | | – | | 2,119 | | 754 | | 3,205 | |
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| | |
| a | Crude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind. |
| b | Excludes NGLs from processing plants in which an interest is held of 58 thousand barrels a day. |
| c | Includes 818 million barrels of NGLs. Also includes 29 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | Includes 33 million barrels of NGLs. Also includes 95 million barrels of crude oil in respect of the 4.47% minority interest in TNK-BP. |
| e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 85 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
Back to Contents
Supplementary information on oil and natural gas (unaudited)continued
| Movements in estimated net proved reserves | | | | | | | | | | | | | | | | 2005 | |
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| Natural gasa | | | | | | | | | | | | | | | billion cubic feet | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2005 | | | | | | | | | | | | | | | | | | |
| Developed | 2,498 | | 248 | | 10,811 | | 4,101 | | 1,624 | | 1,015 | | – | | 282 | | 20,579 | |
| Undeveloped | 1,183 | | 1,254 | | 3,270 | | 10,663 | | 5,419 | | 1,886 | | – | | 1,396 | | 25,071 | |
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| | 3,681 | | 1,502 | | 14,081 | | 14,764 | | 7,043 | | 2,901 | | – | | 1,678 | | 45,650 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | (102 | ) | 11 | | 447 | | 104 | | (133 | ) | 152 | | – | | 15 | | 494 | |
| Purchases of reserves-in-place | – | | – | | 66 | | 2 | | – | | – | | – | | – | | 68 | |
| Extensions, discoveries and other additions | 21 | | 19 | | 47 | | 225 | | 204 | | 44 | | – | | – | | 560 | |
| Improved recovery | 111 | | 19 | | 1,773 | | 87 | | – | | – | | – | | 10 | | 2,000 | |
| Productionb | (425 | ) | (44 | ) | (1,018 | ) | (888 | ) | (280 | ) | (163 | ) | – | | (80 | ) | (2,898 | ) |
| Sales of reserves-in-place | – | | (1,182 | ) | (14 | ) | (230 | ) | – | | – | | – | | – | | (1,426 | ) |
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| | (395 | ) | (1,177 | ) | 1,301 | | (700 | ) | (209 | ) | 33 | | – | | (55 | ) | (1,202 | ) |
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| At 31 December 2005c | | | | | | | | | | | | | | | | | | |
| Developed | 2,382 | | 245 | | 11,184 | | 3,560 | | 1,459 | | 934 | | – | | 281 | | 20,045 | |
| Undeveloped | 904 | | 80 | | 4,198 | | 10,504 | | 5,375 | | 2,000 | | – | | 1,342 | | 24,403 | |
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| | 3,286 | | 325 | | 15,382 | | 14,064 | | 6,834 | | 2,934 | | – | | 1,623 | | 44,448 | |
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| Equity-accounted entities (BP Share) | | | | | | | | | | | | | | | | | | |
| At 1 January 2005 | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 1,397 | | 107 | | – | | 214 | | 60 | | 1,778 | |
| Undeveloped | – | | – | | – | | 977 | | 69 | | – | | 10 | | 23 | | 1,079 | |
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| | – | | – | | – | | 2,374 | | 176 | | – | | 224 | | 83 | | 2,857 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | – | | – | | – | | 26 | | (81 | ) | – | | 1,337 | | 102 | | 1,384 | |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Extensions, discoveries and other additions | – | | – | | – | | 28 | | – | | – | | – | | – | | 28 | |
| Improved recovery | – | | – | | – | | 66 | | – | | – | | – | | – | | 66 | |
| Productionb | – | | – | | – | | (154 | ) | (19 | ) | – | | (184 | ) | (3 | ) | (360 | ) |
| Sales of reserves-in-place | – | | – | | – | | – | | – | | – | | (119 | ) | – | | (119 | ) |
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| | – | | – | | – | | (34 | ) | (100 | ) | – | | 1,034 | | 99 | | 999 | |
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| At 31 December 2005d | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 1,492 | | 50 | | – | | 1,089 | | 130 | | 2,761 | |
| Undeveloped | – | | – | | – | | 848 | | 26 | | – | | 169 | | 52 | | 1,095 | |
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| | – | | – | | – | | 2,340 | | 76 | | – | | 1,258 | | 182 | | 3,856 | |
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| | |
| a | Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind. |
| b | Includes 174 billion cubic feet of natural gas consumed in operations, 147 billion cubic feet in subsidiaries and 27 billion cubic feet in equity-accounted entities. |
| c | Includes 3,812 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | Includes 57 billion cubic feet of natural gas in respect of the 4.47% minority interest in TNK-BP. |
Back to Contents
Supplementary information on oil and natural gas (unaudited)continued
| Movements in estimated net proved reserves | 2004 | |
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| Crude oila | million barrels | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2004 | | | | | | | | | | | | | | | | | | |
| Developed | 697 | | 236 | | 1,902 | | 385 | | 82 | | 190 | | – | | 73 | | 3,565 | |
| Undeveloped | 245 | | 127 | | 1,499 | | 354 | | 81 | | 632 | | – | | 711 | | 3,649 | |
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| | 942 | | 363 | | 3,401 | | 739 | | 163 | | 822 | | – | | 784 | | 7,214 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | (133 | ) | 1 | | (44 | ) | (92 | ) | 2 | | 19 | | – | | (192 | ) | (439 | ) |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Extensions, discoveries and other additions | 24 | | – | | 74 | | 5 | | 8 | | 48 | | – | | 213 | | 372 | |
| Improved recovery | 57 | | 4 | | 55 | | 31 | | – | | 6 | | – | | 3 | | 156 | |
| Productionb | (121 | ) | (28 | ) | (217 | ) | (63 | ) | (17 | ) | (48 | ) | – | | (21 | ) | (515 | ) |
| Sales of reserves-in-place | – | | – | | (17 | ) | (10 | ) | (6 | ) | – | | – | | – | | (33 | ) |
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| | (173 | ) | (23 | ) | (149 | ) | (129 | ) | (13 | ) | 25 | | – | | 3 | | (459 | ) |
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| At 31 December 2004c | | | | | | | | | | | | | | | | | | |
| Developed | 559 | | 231 | | 2,041 | | 311 | | 65 | | 204 | | – | | 62 | | 3,473 | |
| Undeveloped | 210 | | 109 | | 1,211 | | 299 | | 85 | | 643 | | – | | 725 | | 3,282 | |
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| | 769 | | 340 | | 3,252 | e | 610 | | 150 | | 847 | | – | | 787 | | 6,755 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
| At 1 January 2004 | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 206 | | 1 | | – | | 1,384 | | 705 | | 2,296 | |
| Undeveloped | – | | – | | – | | 134 | | – | | – | | 410 | | 27 | | 571 | |
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| | – | | – | | – | | 340 | | 1 | | – | | 1,794 | | 732 | | 2,867 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | – | | – | | – | | (5 | ) | – | | – | | 382 | | 15 | | 392 | |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | 252 | | – | | 252 | |
| Extensions, discoveries and other additions | – | | – | | – | | 2 | | – | | – | | – | | – | | 2 | |
| Improved recovery | – | | – | | – | | 17 | | – | | – | | 37 | | – | | 54 | |
| Production | – | | – | | – | | (25 | ) | – | | – | | (304 | ) | (55 | ) | (384 | ) |
| Sales of reserves-in-place | – | | – | | – | | – | | – | | – | | (4 | ) | – | | (4 | ) |
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| | – | | – | | – | | (11 | ) | – | | – | | 363 | | (40 | ) | 312 | |
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| At 31 December 2004d | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 204 | | 1 | | – | | 1,863 | | 592 | | 2,660 | |
| Undeveloped | – | | – | | – | | 125 | | – | | – | | 294 | | 100 | | 519 | |
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| | – | | – | | – | | 329 | | 1 | | – | | 2,157 | | 692 | | 3,179 | |
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| a | Crude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind. |
| b | Excludes NGLs from processing plants in which an interest is held of 58 thousand barrels a day. |
| c | Includes 724 million barrels of NGLs. Also includes 40 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | Includes 27 million barrels of NGLs. Also includes 127 million barrels of crude oil in respect of the 5.9% minority interest in TNK-BP. |
| e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 77 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
Back to Contents
Supplementary information on oil and natural gas (unaudited)continued
| Movements in estimated net proved reserves | 2004 | |
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| Natural gasa | billion cubic feet | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2004 | | | | | | | | | | | | | | | | | | |
| Developed | 2,996 | | 262 | | 11,482 | | 4,212 | | 1,976 | | 640 | | – | | 255 | | 21,823 | |
| Undeveloped | 1,095 | | 1,255 | | 3,337 | | 11,531 | | 3,026 | | 2,188 | | – | | 900 | | 23,332 | |
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| | 4,091 | | 1,517 | | 14,819 | | 15,743 | | 5,002 | | 2,828 | | – | | 1,155 | | 45,155 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | (210 | ) | 28 | | (438 | ) | (1,081 | ) | 106 | | 16 | | – | | 558 | | (1,021 | ) |
| Purchases of reserves-in-place | – | | – | | 3 | | 2 | | – | | – | | – | | – | | 5 | |
| Extensions, discoveries and other additions | 127 | | – | | 140 | | 991 | | 2,478 | | 233 | | – | | 3 | | 3,972 | |
| Improved recovery | 134 | | 4 | | 870 | | 76 | | – | | 29 | | – | | 38 | | 1,151 | |
| Productionb | (461 | ) | (47 | ) | (1,111 | ) | (875 | ) | (296 | ) | (102 | ) | – | | (76 | ) | (2,968 | ) |
| Sales of reserves-in-place | – | | – | | (202 | ) | (92 | ) | (247 | ) | (103 | ) | – | | – | | (644 | ) |
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| | (410 | ) | (15 | ) | (738 | ) | (979 | ) | 2,041 | | 73 | | – | | 523 | | 495 | |
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| At 31 December 2004c | | | | | | | | | | | | | | | | | | |
| Developed | 2,498 | | 248 | | 10,811 | | 4,101 | | 1,624 | | 1,015 | | – | | 282 | | 20,579 | |
| Undeveloped | 1,183 | | 1,254 | | 3,270 | | 10,663 | | 5,419 | | 1,886 | | – | | 1,396 | | 25,071 | |
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| | 3,681 | | 1,502 | | 14,081 | | 14,764 | | 7,043 | | 2,901 | | – | | 1,678 | | 45,650 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
| At 1 January 2004 | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 1,591 | | 136 | | – | | 46 | | 58 | | 1,831 | |
| Undeveloped | – | | – | | – | | 916 | | 80 | | – | | 14 | | 28 | | 1,038 | |
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| | – | | – | | – | | 2,507 | | 216 | | – | | 60 | | 86 | | 2,869 | |
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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | – | | – | | – | | (12 | ) | (17 | ) | – | | 341 | | – | | 312 | |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Extensions, discoveries and other additions | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Improved recovery | – | | – | | – | | 23 | | – | | – | | – | | – | | 23 | |
| Production | – | | – | | – | | (144 | ) | (23 | ) | – | | (177 | ) | (3 | ) | (347 | ) |
| Sales of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
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| | – | | – | | – | | (133 | ) | (40 | ) | – | | 164 | | (3 | ) | (12 | ) |
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| At 31 December 2004d | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 1,397 | | 107 | | – | | 214 | | 60 | | 1,778 | |
| Undeveloped | – | | – | | – | | 977 | | 69 | | – | | 10 | | 23 | | 1,079 | |
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| | – | | – | | – | | 2,374 | | 176 | | – | | 224 | | 83 | | 2,857 | |
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| a | Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind. |
| b | Includes 190 billion cubic feet of natural gas consumed in operations, 165 billion cubic feet in subsidiaries and 25 billion cubic feet in equity-accounted entities. |
| c | Includes 4,064 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | Includes 13 billion cubic feet of natural gas in respect of the 5.9% minority interest in TNK-BP. |
Back to Contents
Supplementary information on oil and natural gas (unaudited)continued
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves
The following tables set out the standardized measures of discounted future net cash flows, and changes therein, relating to crude oil and natural gas production from the group’s estimated proved reserves. This information is prepared in compliance with the requirements of FASB Statement of Financial Accounting Standards No. 69 – ‘Disclosures about Oil and Gas Producing Activities’.
Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of year-end crude oil and natural gas prices and exchange rates. Furthermore, both reserves estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. BP cautions against relying on the information presented because of the highly arbitrary nature of assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| At 31 December 2006 | | | | | | | | | | | | | | | | | | |
| Future cash inflowsa | 45,300 | | 18,200 | | 218,900 | | 46,800 | | 36,800 | | 47,700 | | – | | 36,200 | | 449,900 | |
| Future production costb | 20,700 | | 4,700 | | 71,300 | | 14,900 | | 9,400 | | 8,700 | | – | | 7,200 | | 136,900 | |
| Future development costb | 3,300 | | 1,500 | | 18,600 | | 4,900 | | 3,800 | | 6,600 | | – | | 3,900 | | 42,600 | |
| Future taxationc | 10,300 | | 9,400 | | 43,100 | | 12,900 | | 7,000 | | 10,600 | | – | | 5,800 | | 99,100 | |
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| Future net cash flows | 11,000 | | 2,600 | | 85,900 | | 14,100 | | 16,600 | | 21,800 | | – | | 19,300 | | 171,300 | |
| 10% annual discountd | 3,200 | | 1,000 | | 45,600 | | 6,200 | | 9,000 | | 8,400 | | – | | 7,300 | | 80,700 | |
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Standardized measure of discounted futurenet cash flowse | 7,800 | | 1,600 | | 40,300 | | 7,900 | | 7,600 | | 13,400 | | – | | 12,000 | | 90,600 | |
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| At 31 December 2005 | | | | | | | | | | | | | | | | | | |
| Future cash inflowsa | 68,200 | | 18,600 | | 261,800 | | 75,600 | | 34,600 | | 46,300 | | – | | 38,200 | | 543,300 | |
| Future production costb | 21,700 | | 3,900 | | 55,800 | | 15,200 | | 6,900 | | 7,800 | | – | | 7,400 | | 118,700 | |
| Future development costb | 2,200 | | 1,000 | | 16,300 | | 4,300 | | 3,500 | | 6,100 | | – | | 4,600 | | 38,000 | |
| Future taxationc | 17,600 | | 10,200 | | 65,300 | | 28,800 | | 7,300 | | 10,600 | | – | | 6,000 | | 145,800 | |
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| Future net cash flows | 26,700 | | 3,500 | | 124,400 | | 27,300 | | 16,900 | | 21,800 | | – | | 20,200 | | 240,800 | |
| 10% annual discountd | 8,500 | | 1,400 | | 63,700 | | 12,600 | | 9,600 | | 8,700 | | – | | 8,100 | | 112,600 | |
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Standardized measure of discounted futurenet cash flowse | 18,200 | | 2,100 | | 60,700 | | 14,700 | | 7,300 | | 13,100 | | – | | 12,100 | | 128,200 | |
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| At 31 December 2004 | | | | | | | | | | | | | | | | | | |
| Future cash inflowsa | 47,400 | | 21,700 | | 169,500 | | 52,600 | | 27,200 | | 35,000 | | – | | 34,200 | | 387,600 | |
| Future production costb | 19,200 | | 4,500 | | 37,800 | | 14,300 | | 6,700 | | 5,800 | | – | | 6,900 | | 95,200 | |
| Future development costb | 2,200 | | 1,900 | | 10,800 | | 4,400 | | 3,500 | | 4,700 | | – | | 5,100 | | 32,600 | |
| Future taxationc | 9,900 | | 11,200 | | 41,800 | | 16,300 | | 5,200 | | 6,900 | | – | | 5,000 | | 96,300 | |
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| Future net cash flows | 16,100 | | 4,100 | | 79,100 | | 17,600 | | 11,800 | | 17,600 | | – | | 17,200 | | 163,500 | |
| 10% annual discountd | 4,700 | | 2,000 | | 38,100 | | 8,000 | | 6,900 | | 7,500 | | – | | 7,800 | | 75,000 | |
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Standardized measure of discounted futurenet cash flowse | 11,400 | | 2,100 | | 41,000 | | 9,600 | | 4,900 | | 10,100 | | – | | 9,400 | | 88,500 | |
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The following are the principal sources of change in the standardized measure of discounted future net cash flows:
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| Sales and transfers of oil and gas produced, net of production costs | (35,800 | ) | (24,300 | ) | (24,100 | ) |
| Development costs incurred during the year | 8,200 | | 7,100 | | 6,300 | |
| Extensions, discoveries and improved recovery, less related costs | 7,900 | | 10,100 | | 3,100 | |
| Net changes in prices and production costf | (43,900 | ) | 84,200 | | 27,600 | |
| Revisions of previous reserves estimates | (9,500 | ) | (17,400 | ) | (10,700 | ) |
| Net change in taxation | 32,200 | | (20,500 | ) | 1,900 | |
| Future development costs | (7,000 | ) | (5,800 | ) | (3,200 | ) |
| Net change in purchase and sales of reserves-in-place | (2,500 | ) | (2,500 | ) | (1,000 | ) |
| Addition of 10% annual discount | 12,800 | | 8,800 | | 8,100 | |
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| Total change in the standardized measure during the year | (37,600 | ) | 39,700 | | 8,000 | |
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| | |
| a | The year end marker prices used were Brent $58.93/bbl, Henry Hub $5.52/mmBtu (2005 Brent $58.21/bbl, Henry Hub $9.52/mmBtu; 2004 Brent $40.24/bbl, Henry Hub $6.01/mmBtu). |
| b | Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on year-end cost levels and assume continuation of existing economic conditions. Future decommissioning costs are included. |
| c | Taxation is computed using appropriate year-end statutory corporate income tax rates. |
| d | Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. |
| e | Minority interest in BP Trinidad and Tobago LLC amounted to $1,300 million at 31 December 2006 ($2,700 million at 31 December 2005 and $1,600 million at 31 December 2004). |
| f | Net changes in prices and production costs includes the effect of exchange rate movements. |
Back to Contents
Supplementary information on oil and natural gas (unaudited)continued
Equity-accounted entities
In addition, at 31 December 2006 the group’s share of the standardized measure of discounted future net cash flows of equity-accounted entities amounted to $14,700 million ($19,300 million at 31 December 2005 and $10,900 million at 31 December 2004).
Operational and statistical information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage.
Crude oil and natural gas production
The following table shows crude oil and natural gas production for the years ended 31 December 2006, 2005 and 2004.
| Production for the yeara | | | | | | | | | | | | | | | | | | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
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| Crude oilb | | | | | | | | | | | | | thousand barrels per day | |
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| 2006 | 253 | | 61 | | 547 | | 108 | | 44 | | 177 | | – | | 161 | | 1,351 | |
| 2005 | 277 | | 75 | | 612 | | 144 | | 47 | | 175 | | – | | 93 | | 1,423 | |
| 2004 | 330 | | 77 | | 666 | | 173 | | 48 | | 130 | | – | | 56 | | 1,480 | |
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| Natural gasc | | | | | | | | | | | | | million cubic feet per day | |
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| 2006 | 936 | | 91 | | 2,376 | | 2,645 | | 727 | | 430 | | – | | 207 | | 7,412 | |
| 2005 | 1,090 | | 108 | | 2,546 | | 2,384 | | 751 | | 422 | | – | | 211 | | 7,512 | |
| 2004 | 1,174 | | 125 | | 2,749 | | 2,334 | | 775 | | 267 | | – | | 200 | | 7,624 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
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| Crude oilb | | | | | | | | | | | | | thousand barrels per day | |
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| 2006 | – | | – | | – | | 77 | | 1 | | – | | 876 | | 170 | | 1,124 | |
| 2005 | – | | – | | – | | 71 | | – | | – | | 911 | | 157 | | 1,139 | |
| 2004 | – | | – | | – | | 68 | | 2 | | – | | 831 | | 150 | | 1,051 | |
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| Natural gasc | | | | | | | | | | | | | million cubic feet per day | |
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| 2006 | – | | – | | – | | 416 | | 37 | | – | | 544 | | 8 | | 1,005 | |
| 2005 | – | | – | | – | | 375 | | 47 | | – | | 482 | | 8 | | 912 | |
| 2004 | – | | – | | – | | 353 | | 60 | | – | | 458 | | 8 | | 879 | |
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| a | All volumes are net of royalty, whether payable in cash or in kind. |
| b | Crude oil includes natural gas liquids and condensate. |
| c | Natural gas production excludes gas consumed in operations. |
Productive oil and gas wells and acreage
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which the group and its equity-accounted entities had interests as of 31 December 2006. A ‘gross’ well or acre is one in which a whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves.
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| | | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Number of productive wells at 31 December 2006 | | | | | | | | | | | | | | | | | | |
| Oil wellsa | – gross | 270 | | 87 | | 8,226 | | 3,379 | | 351 | | 603 | | 18,967 | | 1,491 | | 33,374 | |
| | – net | 145 | | 27 | | 2,402 | | 1,839 | | 151 | | 524 | | 8,090 | | 198 | | 13,376 | |
| Gas wellsb | – gross | 300 | | 38 | | 17,601 | | 2,256 | | 648 | | 83 | | 42 | | 124 | | 21,092 | |
| | – net | 140 | | 14 | | 11,318 | | 1,377 | | 238 | | 40 | | 20 | | 52 | | 13,199 | |
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| a | Includes approximately 976 gross (281.8 net) multiple completion wells (more than one formation producing into the same well bore). |
| b | Includes approximately 2,283 gross (1,524.6 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well. |
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| | | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Oil and natural gas acreage at 31 December 2006 | | | | | | | | | | | | | | | | | | |
| Developed | – gross | 433 | | 138 | | 7,392 | | 3,161 | | 1,072 | | 477 | | 3,991 | | 1,865 | | 18,529 | |
| | – net | 203 | | 44 | | 4,725 | | 1,470 | | 262 | | 211 | | 1,728 | | 419 | | 9,062 | |
| Undevelopeda | – gross | 2,100 | | 1,053 | | 6,809 | | 12,436 | | 7,765 | | 16,215 | | 13,778 | | 18,684 | | 78,840 | |
| | – net | 1,154 | | 339 | | 4,797 | | 5,861 | | 2,939 | | 9,764 | | 5,694 | | 7,677 | | 38,225 | |
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| a | Undeveloped acreage includes leases and concessions. |
Back to Contents
Supplementary information on oil and natural gas (unaudited)continued
Net oil and gas wells completed or abandoned
The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion.
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| 2006 | | | | | | | | | | | | | | | | | | |
| Exploratory | | | | | | | | | | | | | | | | | | |
| Productive | 0.1 | | 0.1 | | 2.9 | | 0.5 | | 1.0 | | 3.2 | | 15.6 | | 1.4 | | 24.8 | |
| Dry | – | | – | | 7.4 | | 1.0 | | 1.5 | | 0.5 | | 5.7 | | 0.3 | | 16.4 | |
| Development | | | | | | | | | | | | | | | | | | |
| Productive | 4.9 | | 1.6 | | 418.8 | | 154.0 | | 12.4 | | 23.8 | | 227.2 | | 14.5 | | 857.2 | |
| Dry | – | | – | | 4.5 | | 5.0 | | 0.2 | | – | | 20.8 | | 1.0 | | 31.5 | |
| 2005 | | | | | | | | | | | | | | | | | | |
| Exploratory | | | | | | | | | | | | | | | | | | |
| Productive | 0.5 | | 0.8 | | 10.7 | | 2.0 | | 0.3 | | 2.0 | | 14.5 | | – | | 30.8 | |
| Dry | 0.3 | | – | | 6.4 | | 1.0 | | 0.3 | | 1.3 | | 5.2 | | – | | 14.5 | |
| Development | | | | | | | | | | | | | | | | | | |
| Productive | 10.6 | | 3.5 | | 473.9 | | 151.7 | | 22.7 | | 17.9 | | 212.8 | | 12.1 | | 905.2 | |
| Dry | – | | 0.3 | | 5.0 | | 3.3 | | 0.4 | | 1.0 | | 17.7 | | 0.3 | | 28.0 | |
| 2004 | | | | | | | | | | | | | | | | | | |
| Exploratory | | | | | | | | | | | | | | | | | | |
| Productive | – | | – | | 2.1 | | 1.3 | | – | | 6.6 | | 11.0 | | 1.3 | | 22.3 | |
| Dry | – | | – | | 3.2 | | 1.5 | | – | | 2.0 | | 5.2 | | 1.1 | | 13.0 | |
| Development | | | | | | | | | | | | | | | | | | |
| Productive | 10.0 | | 0.3 | | 513.3 | | 138.2 | | 8.6 | | 12.9 | | 166.8 | | 16.0 | | 866.1 | |
| Dry | 0.1 | | – | | 3.0 | | 1.8 | | – | | 2.0 | | 8.7 | | 2.4 | | 18.0 | |
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Drilling and production activities in progress
The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its equity-accounted entities as of 31 December 2006. Suspended development wells and long-term suspended exploratory wells are also included in the table.
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | USA | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| At 31 December 2006 | | | | | | | | | | | | | | | | | | |
| Exploratory | | | | | | | | | | | | | | | | | | |
| Gross | 1 | | – | | 22 | | 6 | | 2 | | 4 | | 6 | | 2 | | 43 | |
| Net | 0.5 | | – | | 10.8 | | 2.8 | | 0.3 | | 1.6 | | 2.2 | | 0.5 | | 18.7 | |
| Development | | | | | | | | | | | | | | | | | | |
| Gross | 3 | | 2 | | 194 | | 43 | | 7 | | 19 | | 30 | | 20 | | 318 | |
| Net | 1.1 | | 0.6 | | 110.6 | | 25.2 | | 1.8 | | 6.7 | | 12.5 | | 5.3 | | 163.8 | |
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Back to Contents
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/ D. J. JACKSON
D. J. Jackson
Company Secretary
Dated: 6 March 2007
