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1 Significant accounting policies continued
Intangible assets with a finite life are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and economic useful life, which can range from three to 15 years. Computer software costs have a useful life of three to five years.
The expected useful lives of assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
The carrying value of intangible assets is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable.
Oil and natural gas exploration and development expenditure
Oil and natural gas exploration and development expenditure is accounted for using the successful efforts method of accounting.
Licence and property acquisition costs
Exploration licence and leasehold property 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 and is depreciated from the commencement of production as described below in the accounting policy for 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 fair value unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable. The cost of the acquired asset is measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the amount given up. The gain or loss on derecognition of the asset given up is recognized in profit or loss.
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 is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. 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, field development and future decommissioning 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 approved future development expenditure required to develop reserves.
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:
|
| Land improvements | 15 to 25 years | |
| Buildings | 20 to 50 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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1 Significant accounting policies continued
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. If any such indication of impairment exists, the group makes an estimate of its recoverable amount. 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. 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.
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. Financial assets are recognized initially at fair value, normally being the transaction price plus, in the case of financial assets not at fair value through profit or loss, directly attributable transaction costs.
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. This category of financial assets includes trade and other receivables.
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 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. 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 effective 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 and hedging activities.
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 profit or loss.
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.
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1 Significant accounting policies continued
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 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.
Financial liabilities
Financial liabilities are classified as financial liabilities at fair value through profit or loss; derivatives designated as hedging instruments in an effective hedge; or as financial liabilities measured at amortized cost, as appropriate. Financial liabilities include trade and other payables, accruals, finance debt and derivative financial instruments. The group determines the classification of its financial liabilities at initial recognition. The measurement of financial liabilities depends on their classification, as follows:
Financial liabilities at fair value through profit or loss
Derivatives, other than those designated as effective hedging instruments, are classified as held for trading and are included in this category. These liabilities 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 and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value. For interest-bearing loans and borrowings this is the fair value of the proceeds received net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities 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 finance costs.
This category of financial liabilities includes trade and other payables and finance debt.
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 commencement of the lease term at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Finance charges are allocated to each period so as to achieve a constant rate of interest on the remaining balance of the liability and 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 and hedging activities
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. 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.
Gains or losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement. |
| 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 asset or liability or a highly probable forecast transaction. |
| – | Hedges of a net investment in a foreign operation. |
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1 Significant accounting policies continued
At the inception of a hedge relationship the group formally designates and documents the hedge relationship for which the group wishes to claim hedge accounting, together with the risk management objective and strategy for undertaking the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and how the entity will assess the hedging instrument effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged item. Such hedges are expected at inception to be highly effective in achieving offsetting changes in fair value or cash flows.
Hedges meeting the criteria for hedge accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss.
The group applies fair value hedge accounting for hedging fixed interest rate risk on borrowings. The gain or loss relating to the effective portion of the interest rate swap is recognized in the income statement within finance costs, offsetting the amortization of the interest on the underlying borrowings.
If the criteria for hedge accounting are no longer met, or if the group revokes the designation, the adjustment to the carrying amount of a hedged item for which the effective interest rate method is used is amortized to profit or loss over the period to maturity.
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. The gain or loss relating to the effective portion of interest rate swaps hedging variable rate borrowings is recognized in the income statement within finance costs.
Where the hedged item is the cost of a non-financial asset or liability, such as a forecast transaction for the purchase of property, plant and equipment, 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.
Hedges of a net investment in a foreign operation
For hedges of a net investment in a foreign operation, 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 operation is sold or partially disposed.
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 appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability. 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. Where discounting is used, the increase in the provision due to the passage of time is recognized as 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 reliably estimated. Generally, the timing of recognition 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 reliable 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.
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1 Significant accounting policies continued
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 asset.
Other than the unwinding discount on the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding item of 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 equity instruments 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.
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 of 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). 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. Interest and penalties relating to tax are also included in income tax expense.
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. Any liability relating to unrecognized tax benefits is included in current tax payable on the group balance sheet.
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.
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1 Significant accounting policies continued
| 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 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 taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. |
| Deferred tax assets are 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 in a 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. |
| |
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 the customs 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 the profit and loss account reserve. 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.
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 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.
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1 Significant accounting policies continued
Impact of new International Financial Reporting Standards
Adopted for 2007
The following new IFRS, amendment to IFRS and IFRIC interpretations have been adopted by the group with effect from 1 January 2007.
IFRS 7 ‘Financial Instruments: Disclosures’ was issued in August 2005 and replaced the disclosure requirements previously contained in IAS 32 ‘Financial Instruments: Presentation and Disclosure’. The group has disclosed in its annual report additional information about its financial instruments, their significance and the nature and extent of risks to which they give rise. More specifically, the group has also made specified disclosures about market risk, credit risk and liquidity risk. There was no effect on the group’s reported income or net assets as a result of adoption of this new standard.
Also in August 2005, the IASB issued Amendment to IAS 1 ‘Presentation of Financial Statements’ – Capital Disclosures, 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. The group has included the required disclosures in its annual report. There was no effect on the group’s reported income or net assets as a result of adoption of this amendment.
In addition, in 2007 BP has adopted IFRIC 10 ‘Interim Financial Reporting and Impairment’ and early adopted IFRIC 11 ‘IFRS 2 – Group and Treasury Share Transactions’. There were no changes in the group’s accounting policies 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.
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 been adopted by the EU.
In September 2007, the IASB issued Amendments to IAS 1 ‘Presentation of Financial Statements’ – A Revised Presentation, which requires separate presentation of owner and non-owner changes in equity by introducing the statement of comprehensive income. The statement of recognized income and expense will no longer be presented. Whenever there is a restatement or reclassification, an additional balance sheet, as at the beginning of the earliest period presented, will be required to be published. The revised standard is effective for annual periods beginning on or after 1 January 2009. There will be no effect on the group’s reported income or net assets. IAS 1 revised has not yet been adopted by the EU.
An amendment to IAS 23 ‘Borrowing Costs’ was issued by the IASB in March 2007 and eliminates the option of recognizing borrowing costs immediately as an expense if they are directly attributable to the acquisition, construction or production of a qualifying asset. The amended standard is effective for annual periods beginning on or after 1 January 2009. There will be no effect on the group’s reported income or net assets. This amendment has not yet been adopted by the EU.
In January 2008, the IASB issued a revised version of IFRS 3 ‘Business Combinations’. The revised standard still requires the purchase method of accounting to be applied to business combinations but will introduce some changes to existing accounting treatment. For example, contingent consideration should be measured at fair value at the date of acquisition and subsequently remeasured to fair value with changes recognized in profit or loss. Goodwill may be calculated based on the parent’s share of net assets or it may include goodwill related to the minority interest. All transaction costs will be expensed. The standard is applicable to business combinations occurring in accounting periods beginning on or after 1 July 2009. Assets and liabilities arising from business combinations occurring before the date of adoption by the group will not be restated and thus there will be no effect on the group’s reported income or net assets on adoption. The revised standard has not yet been adopted by the EU.
Also in January 2008, the IASB issued an amended version of IAS 27 ‘Consolidated and Separate Financial Statements’. This requires the effects of all transactions with non-controlling interests to be recorded in equity if there is no change in control. Such transactions will no longer result in goodwill or gains or losses. When control is lost, any remaining interest in the entity is remeasured to fair value and a gain or loss recognized in profit or loss. The amendments are effective for annual periods beginning on or after 1 July 2009 and are to be applied retrospectively, with certain exceptions. BP has not yet completed its evaluation of the effect of adopting this amendment. The revised standard has not yet been adopted by the EU.
An amendment to IFRS 2 ‘Share-based Payment’ was issued in January 2008, clarifying that only service conditions and performance conditions are vesting conditions, and other features of a share-based payment are not vesting conditions. In addition, it specifies that all cancellations, whether by the entity or by other parties, should receive the same accounting treatment. The amendment is effective for annual periods beginning on or after 1 January 2009 and has not yet been adopted by the EU. BP has not yet completed its evaluation of the effect of adopting this amendment.
In February 2008, the IASB issued Amendments to IAS 32 ‘Financial Instruments: Presentation’ and IAS 1 ‘Presentation of Financial Statements’ – Puttable Financial Instruments and Obligations Arising on Liquidation. The amended standards require entities to classify as equity certain financial instruments provided certain criteria are met. The instruments to be classified as equity are puttable financial instruments and those instruments that impose an obligation on the entity to deliver to another party a pro rata share of the net assets of the entity only on liquidation. The amendments are effective for annual periods beginning on or after 1 January 2009 and have not yet been adopted by the EU. BP has not yet completed its evaluation of the effect of adopting these amendments.
Three IFRIC interpretations have been issued but are not yet effective and have not yet been adopted by the EU.
IFRIC 12 ‘Service Concession Arrangements’ gives guidance on the accounting by operators for public-to-private service concession arrangements. The directors do not anticipate that the adoption of this interpretation will have a material effect on the reported income or net assets of the group. We plan to adopt this interpretation with effect from 1 January 2008.
IFRIC 13 ‘Customer Loyalty Programmes’ addresses the accounting by entities that grant loyalty award credits (e.g. ‘points’ or travel miles) to customers who buy other goods or services. The directors do not anticipate that the adoption of this interpretation will have a material effect on the reported income or net assets of the group. We plan to adopt this interpretation with effect from 1 January 2009.
IFRIC 14 ‘IAS 19 – The Limit on a Defined Benefit Asset, Minimum Funding Requirements, and their Interaction’ provides clarification regarding how to determine whether a surplus may be recognized on the balance sheet in relation to a retirement benefit plan. The directors do not anticipate that the adoption of this interpretation will have a material effect on the reported income or net assets of the group. We plan to adopt this interpretation with effect from 1 January 2008.
Back to Contents
2 Acquisitions
Acquisitions in 2007
BP made a number of acquisitions in 2007 for a total consideration of $1,200 million. These business combinations were predominantly in the Refining and Marketing segment, the most significant of which was the acquisition of Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The acquisition included Chevron’s 31% minority shareholding in Nerefco, its 31% shareholding in the 22.5 megawatt wind farm co-located at the refinery as well as a 22.8% shareholding in the TEAM joint venture terminal and shareholdings in two local pipelines linking the TEAM terminal to the refinery. Fair value adjustments were made to the acquired assets and liabilities. Goodwill of $270 million arose on these acquisitions.
Acquisitions in 2006
BP made a number of acquisitions in 2006 for a total consideration of $256 million. All these business combinations were in the Gas, Power and Renewables segment. 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 acquisitions in 2005 for a total consideration of $84 million. No significant fair value adjustments were made to the acquired assets and liabilities. Goodwill of $27 million arose on these acquisitions. Also in 2005, additional goodwill of $59 million was recognized relating to the 2004 acquisition from Solvay of the remaining interests in two equity-accounted entities. This goodwill arose due to final closing adjustments and selling costs and was written off.
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3 Non-current assets held for sale and discontinued operations
Non-current assets held for sale
On 5 December 2007, BP announced it had signed a memorandum of understanding with Husky Energy Inc. to form an integrated North American oil sands business. BP will contribute its Toledo refinery to a US joint venture in return for Husky contributing its Sunrise field to a Canadian joint venture. The transaction is expected to be completed by the end of March 2008. At 31 December 2007, certain Toledo refinery assets and associated liabilities were classified as a disposal group held for sale. No impairment loss has been recognized in relation to this disposal group.
On 27 June 2006, BP announced its intention to sell the Coryton refinery in the UK, following a review of its European refinery portfolio, that concluded that the group would optimize 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 was 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 Toledo and Coryton disposal groups, both reported within the Refining and Marketing segment, classified as held for sale at 31 December 2007 and 2006 respectively, are set out below.
| | | | $ million | |
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| | 2007 | | 2006 | |
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| Assets | | | | |
| Property, plant and equipment | 635 | | 564 | |
| Goodwill | 90 | | 60 | |
| Inventories | 561 | | 454 | |
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| Assets classified as held for sale | 1,286 | | 1,078 | |
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| Liabilities | | | | |
| Current liabilities | 163 | | 54 | |
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| Liabilities directly associated with assets classified as held for sale | 163 | | 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 were recycled to the income statement. The disposal of the Coryton disposal group was completed in May 2007. For further information see Note 4.
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 was 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.
| | | | | | $ million | |
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|
| | 2007 | | 2006 | | 2005 | |
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| Total revenues and other income | – | | – | | 12,441 | |
| Expenses | – | | – | | 11,709 | |
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|
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|
|
| Profit (loss) before interest and taxation | – | | – | | 732 | |
| Other finance income (expense) | – | | – | | 3 | |
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|
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|
|
|
| Profit (loss) before taxation and loss recognized on remeasurement to fair value less costs to sell and on disposal | – | | – | | 735 | |
| 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 | |
| Tax (charge) credit | | | | | | |
| on profit (loss) before loss recognized on remeasurement to fair value less costs to sell and on disposal | – | | 166 | | (306 | ) |
| on loss recognized on the remeasurement to fair value less costs to sell and on disposal | – | | (7 | ) | 346 | |
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|
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| Profit (loss) from Innovene operations | – | | (25 | ) | 184 | |
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| Earnings (loss) per share from Innovene operations – cents | | | | | | |
| Basic | – | | (0.13 | ) | 0.87 | |
| Diluted | – | | (0.12 | ) | 0.86 | |
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| The cash flows of Innovene operations are presented below | | | | | | |
| Net cash provided by operating activities | – | | – | | 970 | |
| Net cash used in investing activities | – | | – | | (524 | ) |
| Net cash used in financing activities | – | | – | | (446 | ) |
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Further information is contained in Note 4.
Back to Contents
4 Disposals
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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| Proceeds from the sale of Innovene operations | – | | (34 | ) | 8,304 | |
| Proceeds from the sale of other businesses | 2,518 | | 325 | | 93 | |
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|
|
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| Proceeds from the sale of businesses | 2,518 | | 291 | | 8,397 | |
| Proceeds from disposal of fixed assets | 1,749 | | 5,963 | | 2,803 | |
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| | 4,267 | | 6,254 | | 11,200 | |
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| By business | | | | | | |
| Exploration and Production | 1,276 | | 4,005 | | 1,416 | |
| Refining and Marketing | 2,953 | | 1,789 | | 888 | |
| Gas, Power and Renewables | 31 | | 297 | | 540 | |
| Other businesses and corporate | 7 | | 163 | | 8,356 | |
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| | 4,267 | | 6,254 | | 11,200 | |
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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. The group may also dispose of other assets, such as refineries, when this meets strategic objectives.
Cash received during the year from disposals amounted to $4.3 billion (2006 $6.3 billion and 2005 $11.2 billion). The major transactions in 2007 were the disposals of our Coryton refinery, our exploration and production and gas infrastructure business in the Netherlands, our interest in non-core Permian assets in the US and our interest in the Entrada field in the Gulf of Mexico.
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 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 2007, the major transactions were the disposal of an exploration and production and gas infrastructure business in the Netherlands and the divestments of our interests in non-core Permian assets in the US and in the Entrada field in the Gulf of Mexico. We also sold our interests in a number of fields in Egypt, Canada and the US.
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.
Refining and Marketing
The churn of retail assets represents a significant element of the total in all three years. In addition, in 2007, we disposed of the Coryton refinery in the UK, our interest in the West Texas Pipeline in the US, our interest in the Samsung Petrochemical Company in South Korea and other interests in France, Brazil and Africa.
During 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.
Back to Contents
4 Disposals continued
Gas, Power and Renewables
There were no significant disposals in 2007. 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.
Other businesses and corporate
There were no significant disposals in 2007. During 2006, the group disposed of miscellaneous non-core businesses and assets. 2005 includes the proceeds from the sale of Innovene.
| Summarized financial information for the sale of businesses is shown below. | | | | | | |
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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| The disposals comprise the following | | | | | | |
| Non-current assets | 753 | | 143 | | 6,452 | |
| Other current assets | 587 | | 169 | | 4,779 | |
| Non-current liabilities | (64 | ) | (10 | ) | (364 | ) |
| Current liabilities | (27 | ) | (70 | ) | (2,488 | ) |
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| Total carrying amount of net assets disposed | 1,249 | | 232 | | 8,379 | |
| Recycling of foreign exchange on disposal | (147 | ) | – | | – | |
| Costs on disposal | 22 | | – | | – | |
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| | 1,124 | | 232 | | 8,379 | |
| Profit (loss) on sale of businesses | 1,384 | | 167 | | 18 | |
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| Total consideration | 2,508 | | 399 | | 8,397 | |
| Consideration received (receivable)a | 10 | | (74 | ) | – | |
| Closing adjustments associated with the sale of Innovene | – | | (34 | ) | – | |
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| Proceeds from the sale of businessesb | 2,518 | | 291 | | 8,397 | |
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| a | Consideration received from prior year disposals or not yet received from current year disposals. |
| b | Net of cash and cash equivalents disposed of $115 million (2006 $2 million and 2005 $15 million). |
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5 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 internal financial reporting systems.
In 2007, BP had 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, development and production, together with related pipeline, transportation and processing activities. The activities of Refining and Marketing include the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum and chemicals products. Gas, Power and Renewables activities included marketing and trading of gas and power, marketing of liquefied natural gas (LNG), natural gas liquids (NGLs) and low-carbon power generation through our Alternative Energy business. The group is managed on an integrated basis.
Other businesses and corporate comprises Treasury (which in the segmental analysis includes all of the group’s cash, cash equivalents and associated interest income), the group’s aluminium asset and corporate activities worldwide.
The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred.
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 groupings of countries 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.
| | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | 2007 | |
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| | | | | | Gas, | | Other | | Consolidation | | | |
| | Exploration | | Refining | | Power | | businessess | | adjustment | | | |
| | and | | and | | and | | and | | and | | Total | |
| By business | Production | | Marketing | | Renewables | | corporate | | eliminations | | group | |
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| Sales and other operating revenues | | | | | | | | | | | | |
| Segment sales and other operating revenues | 54,550 | | 250,866 | | 21,369 | | 843 | | (43,263 | ) | 284,365 | |
| Less: sales between businesses | (38,803 | ) | (2,024 | ) | (2,436 | ) | – | | 43,263 | | – | |
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| Third party sales | 15,747 | | 248,842 | | 18,933 | | 843 | | – | | 284,365 | |
| Equity-accounted earnings | 3,061 | | 538 | | 233 | | – | | – | | 3,832 | |
| Interest and other revenues | 330 | | 134 | | 123 | | 167 | | – | | 754 | |
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| Total revenues | 19,138 | | 249,514 | | 19,289 | | 1,010 | | – | | 288,951 | |
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| Segment results | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 26,938 | | 6,072 | | 674 | | (1,128 | ) | (204 | ) | 32,352 | |
| Finance costs and other finance income/expense | – | | – | | – | | – | | (741 | ) | (741 | ) |
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| Profit (loss) before taxation | 26,938 | | 6,072 | | 674 | | (1,128 | ) | (945 | ) | 31,611 | |
| Taxation | – | | – | | – | | – | | (10,442 | ) | (10,442 | ) |
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| Profit (loss) for the year | 26,938 | | 6,072 | | 674 | | (1,128 | ) | (11,387 | ) | 21,169 | |
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| Assets and liabilities | | | | | | | | | | | | |
| Segment assets | 108,874 | | 95,691 | | 19,889 | | 17,188 | | (6,271 | ) | 235,371 | |
| Current tax receivable | – | | – | | – | | – | | 705 | | 705 | |
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|
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| Total assets | 108,874 | | 95,691 | | 19,889 | | 17,188 | | (5,566 | ) | 236,076 | |
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| Includes | | | | | | | | | | | | |
| Equity-accounted investments | 16,388 | | 5,268 | | 1,007 | | 29 | | – | | 22,692 | |
| | | | | | | | | | | | | |
| Segment liabilities | (23,792 | ) | (41,053 | ) | (13,439 | ) | (14,940 | ) | 5,342 | | (87,882 | ) |
| Current tax payable | – | | – | | – | | – | | (3,282 | ) | (3,282 | ) |
| Finance debt | – | | – | | – | | – | | (31,045 | ) | (31,045 | ) |
| Deferred tax liabilities | – | | – | | – | | – | | (19,215 | ) | (19,215 | ) |
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| Total liabilities | (23,792 | ) | (41,053 | ) | (13,439 | ) | (14,940 | ) | (48,200 | ) | (141,424 | ) |
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| Other segment information | | | | | | | | | | | | |
| Capital expenditure and acquisitions | | | | | | | | | | | | |
| Goodwill and other intangible assets | 2,153 | | 581 | | 98 | | 21 | | – | | 2,853 | |
| Property, plant and equipment | 11,360 | | 4,565 | | 746 | | 216 | | – | | 16,887 | |
| Other | 393 | | 440 | | 30 | | 38 | | – | | 901 | |
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| Total | 13,906 | | 5,586 | | 874 | | 275 | | – | | 20,641 | |
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| Depreciation, depletion and amortization | 7,720 | | 2,430 | | 215 | | 214 | | – | | 10,579 | |
| Impairment losses | 292 | | 1,186 | | 40 | | 43 | | – | | 1,561 | |
| Impairment reversals | 237 | | – | | – | | – | | – | | 237 | |
| Losses on sale of businesses and fixed assets | 42 | | 313 | | – | | – | | – | | 355 | |
| Gains on sale of businesses and fixed assets | 949 | | 1,464 | | 12 | | 62 | | – | | 2,487 | |
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Back to Contents
5 Segmental analysis continued
| | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | 2006 | |
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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 | 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 | |
| Interest and other revenues | 283 | | 106 | | 77 | | 235 | | – | | 701 | | – | | – | | 701 | |
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| Total revenues | 20,229 | | 229,226 | | 19,904 | | 1,243 | | – | | 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 income/expense | – | | – | | – | | – | | (516 | ) | (516 | ) | – | | – | | (516 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 | | | | | | | |
| Current tax receivable | – | | – | | – | | – | | 544 | | 544 | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets | 99,310 | | 80,964 | | 27,398 | | 14,184 | | (4,255 | ) | 217,601 | | | | | | | |
|
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|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
| Includes | | | | | | | | | | | | | | | | | | |
| Equity-accounted investments | 15,510 | | 4,675 | | 853 | | 11 | | – | | 21,049 | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| 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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|
|
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|
|
|
|
|
|
|
|
| Other segment information | | | | | | | | | | | | | | | | | | |
| Capital expenditure and acquisitions | | | | | | | | | | | | | | | | | | |
| Goodwill and other intangible assets | 1,614 | | 253 | | 256 | | 43 | | – | | 2,166 | | | | | | | |
| Property, plant and equipment | 10,227 | | 2,733 | | 337 | | 232 | | – | | 13,529 | | | | | | | |
| Other | 1,277 | | 158 | | 95 | | 6 | | – | | 1,536 | | | | | | | |
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|
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|
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|
|
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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
5 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 | |
| Interest and other revenues | 290 | | 151 | | 15 | | 233 | | – | | 689 | | (76 | ) | – | | 613 | |
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|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
| Total revenues | 18,126 | | 202,319 | | 22,678 | | 13,263 | | – | | 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 income/expense | – | | – | | – | | – | | (758 | ) | (758 | ) | (3 | ) | – | | (761 | ) |
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|
|
|
|
|
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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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|
|
|
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|
|
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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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|
|
|
|
|
|
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|
|
|
|
|
|
|
|
| Other segment information | | | | | | | | | | | | | | | | | | |
| 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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| 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
5 Segmental analysis continued
| | | | | | | | | | | | $ million | |
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|
| | | | | | | | | | | | 2007 | |
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|
|
| | | | | | | | | | Consolidation | | | |
| | | | Rest of | | | | Rest of | | adjustment and | | | |
| By geographical area | UK | | Europe | | US | | World | | eliminations | | Total | |
|
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|
|
|
|
|
|
|
|
|
|
|
| Sales and other operating revenues | | | | | | | | | | | | |
| Segment sales and other operating revenues | 109,800 | | 78,366 | | 105,120 | | 74,462 | | – | | 367,748 | |
| Less: sales between areas | (48,651 | ) | (12,024 | ) | (2,801 | ) | (19,907 | ) | – | | (83,383 | ) |
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|
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|
|
|
|
|
| Third party sales | 61,149 | | 66,342 | | 102,319 | | 54,555 | | – | | 284,365 | |
| Equity-accounted earnings | 1 | | 55 | | 144 | | 3,632 | | – | | 3,832 | |
| Interest and other revenues | 222 | | 78 | | 142 | | 312 | | – | | 754 | |
|
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|
|
|
|
|
|
|
|
|
|
|
| Total revenues | 61,372 | | 66,475 | | 102,605 | | 58,499 | | – | | 288,951 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Segment results | | | | | | | | | | | | |
| Profit (loss) before interest and tax | 4,613 | | 4,164 | | 7,439 | | 16,136 | | – | | 32,352 | |
| Finance costs and other finance income/expense | (17 | ) | (287 | ) | (524 | ) | 87 | | – | | (741 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit before taxation | 4,596 | | 3,877 | | 6,915 | | 16,223 | | – | | 31,611 | |
| Taxation | (2,027 | ) | (949 | ) | (2,593 | ) | (4,873 | ) | – | | (10,442 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year | 2,569 | | 2,928 | | 4,322 | | 11,350 | | – | | 21,169 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Assets and liabilities | | | | | | | | | | | | |
| Segment assets | 53,065 | | 34,658 | | 81,911 | | 76,504 | | (10,767 | ) | 235,371 | |
| Current tax receivable | 3 | | 27 | | 468 | | 207 | | – | | 705 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total assets | 53,068 | | 34,685 | | 82,379 | | 76,711 | | (10,767 | ) | 236,076 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Includes | | | | | | | | | | | | |
| Equity-accounted investments | 142 | | 1,970 | | 1,659 | | 18,921 | | – | | 22,692 | |
| | | | | | | | | | | | | |
| Segment liabilities | (30,043 | ) | (18,985 | ) | (31,314 | ) | (18,307 | ) | 10,767 | | (87,882 | ) |
| Current tax payable | (963 | ) | (658 | ) | (104 | ) | (1,557 | ) | – | | (3,282 | ) |
| Finance debt | (20,085 | ) | (200 | ) | (8,238 | ) | (2,522 | ) | – | | (31,045 | ) |
| Deferred tax liabilities | (3,397 | ) | (1,124 | ) | (10,656 | ) | (4,038 | ) | – | | (19,215 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total liabilities | (54,488 | ) | (20,967 | ) | (50,312 | ) | (26,424 | ) | 10,767 | | (141,424 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other segment information | | | | | | | | | | | | |
| Capital expenditure and acquisitions | | | | | | | | | | | | |
| Goodwill and other intangible assets | 453 | | 298 | | 817 | | 1,285 | | – | | 2,853 | |
| Property, plant and equipment | 1,141 | | 2,489 | | 6,516 | | 6,741 | | – | | 16,887 | |
| Other | 78 | | 253 | | 154 | | 416 | | – | | 901 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total | 1,672 | | 3,040 | | 7,487 | | 8,442 | | – | | 20,641 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Depreciation, depletion and amortization | 2,133 | | 959 | | 3,558 | | 3,929 | | – | | 10,579 | |
| Exploration expense | 46 | | – | | 252 | | 458 | | – | | 756 | |
| Impairment losses | 315 | | 136 | | 723 | | 387 | | – | | 1,561 | |
| Impairment reversals | – | | – | | 237 | | – | | – | | 237 | |
| Losses on sale of businesses and fixed assets | 2 | | 77 | | 233 | | 43 | | – | | 355 | |
| Gains on sale of businesses and fixed assets | 893 | | 655 | | 770 | | 169 | | – | | 2,487 | |
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|
Back to Contents
5 Segmental analysis continued
| | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | 2006 | |
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|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | Consolidation | | | |
| | | | Rest of | | | | Rest of | | adjustment and | | | |
| By geographical area | UK | | Europe | | US | | World | | eliminations | | Total | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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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|
|
|
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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 | |
| Interest and other revenues | 258 | | 7 | | 107 | | 329 | | – | | 701 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total revenues | 54,839 | | 61,967 | | 95,137 | | 58,659 | | – | | 270,602 | |
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|
|
|
|
|
|
|
|
|
|
|
|
| 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 income/expense | 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 | |
| Current 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 | | | | | | | | | | | | |
| Goodwill and other intangible assets | 421 | | 53 | | 969 | | 723 | | – | | 2,166 | |
| Property, plant and equipment | 1,120 | | 916 | | 5,531 | | 5,962 | | – | | 13,529 | |
| Other | 46 | | 22 | | 92 | | 1,376 | | – | | 1,536 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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
5 Segmental analysis continued
| | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | 2005 | |
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|
|
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|
|
|
| | | | | | | | | | Consolidation | | | |
| | | | Rest of | | | | Rest of | | adjustment and | | | |
| By geographical area | UK | | Europe | | US | | 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 | ) |
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|
|
|
|
|
|
|
|
| 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 | |
| Interest and other revenues | (533 | ) | 152 | | 695 | | 299 | | – | | 613 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total revenues | 48,544 | | 54,822 | | 93,792 | | 46,790 | | – | | 243,948 | |
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|
|
|
|
|
|
|
|
|
|
|
|
| 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 | ) |
|
|
|
|
|
|
|
|
|
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|
|
|
| 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 | |
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|
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|
|
|
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|
|
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| Profit for the year | 1,032 | | 3,401 | | 8,310 | | 9,574 | | – | | 22,317 | |
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| Other segment information | | | | | | | | | | | | |
| 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
6 Interest and other revenues
| | | | | | | $ million | |
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| | | 2007 | | 2006 | | 2005 | |
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| Related to financial instruments | | | | | | | |
| Interest income from available-for-sale financial assets | | 5 | | 13 | | 14 | |
| Dividend income from available-for-sale financial assets | | 29 | | 32 | | 25 | |
| Interest income from loans and receivables | | 175 | | 186 | | 101 | |
|
|
|
|
|
|
|
|
| | | 209 | | 231 | | 140 | |
|
|
|
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|
|
|
| Not related to financial instruments | | | | | | | |
| Interest from equity-accounted investments | | 172 | | 176 | | 141 | |
| Other interest | | 97 | | 62 | | 116 | |
| Other income | | 276 | | 232 | | 292 | |
|
|
|
|
|
|
|
|
| | | 545 | | 470 | | 549 | |
|
|
|
|
|
|
|
|
| | | 754 | | 701 | | 689 | |
| Innovene operations | | – | | – | | (76 | ) |
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|
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| Continuing operations | | 754 | | 701 | | 613 | |
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7 Gains on sale of businesses and fixed assets
| | | | | | | $ million | |
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| | | 2007 | | 2006 | | 2005 | |
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| Gains on sale of businesses | | | | | | | |
| Exploration and Production | | 534 | | – | | – | |
| Refining and Marketing | | 850 | | 104 | | 18 | |
| Other businesses and corporate | | – | | 63 | | – | |
|
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|
|
|
|
|
|
| | | 1,384 | | 167 | | 18 | |
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|
|
| Gains on sale of fixed assets | | | | | | | |
| Exploration and Production | | 415 | | 2,309 | | 1,198 | |
| Refining and Marketing | | 614 | | 1,008 | | 223 | |
| Gas, Power and Renewables | | 12 | | 193 | | 55 | |
| Other businesses and corporate | | 62 | | 37 | | 47 | |
|
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|
|
|
|
|
|
| | | 1,103 | | 3,547 | | 1,523 | |
|
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|
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|
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|
|
| | | 2,487 | | 3,714 | | 1,541 | |
| Innovene operations | | – | | – | | (3 | ) |
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|
|
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|
|
| Continuing operations | | 2,487 | | 3,714 | | 1,538 | |
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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 2007 that resulted in gains were the disposal of an exploration and production and gas infrastructure business in the Netherlands and the divestments of our interests in non-core Permian assets in the US and in the Entrada field in the Gulf of Mexico.
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.
Refining and Marketing
During 2007, the group divested the Coryton refinery in the UK, its interest in the West Texas Pipeline in the US and its interest in the Samsung Petrochemical Company in South Korea.
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.
Gas, Power and Renewables
There were no significant disposals in 2007.
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.
Other businesses and corporate
There were no significant disposals in 2007.
During 2006, the group disposed of its ethylene oxide business.
Additional information on the sale of businesses and fixed assets is given in Note 4.
Back to Contents
8 Production and similar taxes
| | | | | | | $ million | |
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|
|
|
|
|
|
|
| | | 2007 | | 2006 | | 2005 | |
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|
|
| UK | | 197 | | 260 | | 495 | |
| Overseas | | 3,816 | | 3,361 | | 2,515 | |
|
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|
|
|
|
|
|
| | | 4,013 | | 3,621 | | 3,010 | |
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|
|
9 Depreciation, depletion and amortization
| | | | | | | $ million | |
|
|
|
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|
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|
|
| By business | | 2007 | | 2006 | | 2005 | |
|
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|
|
|
|
|
|
| Exploration and Productiona | | | | | | | |
| UK | | 1,683 | | 1,720 | | 1,663 | |
| Rest of Europe | | 211 | | 223 | | 228 | |
| US | | 2,273 | | 2,236 | | 2,426 | |
| Rest of World | | 3,553 | | 2,354 | | 1,716 | |
|
|
|
|
|
|
|
|
| | | 7,720 | | 6,533 | | 6,033 | |
|
|
|
|
|
|
|
|
| Refining and Marketing | | | | | | | |
UKb | | 286 | | 303 | | 316 | |
| Rest of Europe | | 729 | | 603 | | 687 | |
| US | | 1,077 | | 1,048 | | 1,082 | |
| Rest of World | | 338 | | 290 | | 297 | |
|
|
|
|
|
|
|
|
| | | 2,430 | | 2,244 | | 2,382 | |
|
|
|
|
|
|
|
|
| Gas, Power and Renewables | | | | | | | |
| UK | | 15 | | 18 | | 47 | |
| Rest of Europe | | 17 | | 13 | | 20 | |
| US | | 148 | | 117 | | 109 | |
| Rest of World | | 35 | | 44 | | 59 | |
|
|
|
|
|
|
|
|
| | | 215 | | 192 | | 235 | |
|
|
|
|
|
|
|
|
| Other businesses and corporate | | | | | | | |
| UK | | 149 | | 98 | | 203 | |
| Rest of Europe | | 2 | | 1 | | 130 | |
| US | | 60 | | 58 | | 187 | |
| Rest of World | | 3 | | 2 | | 13 | |
|
|
|
|
|
|
|
|
| | | 214 | | 159 | | 533 | |
|
|
|
|
|
|
|
|
| | | | | | | | |
| By geographical area | | | | | | | |
|
|
|
|
|
|
|
|
UKb | | 2,133 | | 2,139 | | 2,229 | |
| Rest of Europe | | 959 | | 840 | | 1,065 | |
| US | | 3,558 | | 3,459 | | 3,804 | |
| Rest of World | | 3,929 | | 2,690 | | 2,085 | |
|
|
|
|
|
|
|
|
| | | 10,579 | | 9,128 | | 9,183 | |
|
|
|
|
|
|
|
|
| Innovene operations | | – | | – | | (412 | ) |
|
|
|
|
|
|
|
|
| Continuing operations | | 10,579 | | 9,128 | | 8,771 | |
|
|
|
|
|
|
|
|
| a | At the end of 2006, BP adopted the US Securities and Exchange Commission (SEC) rules for estimating oil and natural gas reserves 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). |
| | This change in accounting estimate had 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 was applied prospectively, with no restatement of prior periods’ results. The group’s actual DD&A charge for 2006 was $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 that was used to calculate DD&A for the last three months of 2006. For 2007, it was estimated that the DD&A charge would increase by approximately $400 million to $500 million as a result of the change. Over the life of a field this change would have no overall effect on DD&A. |
| | The main differences between the UK SORP and SEC rules 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 in 2006 represented a simplification of the group’s reserves reporting, as only one set of reserves estimates is disclosed. In addition, the use of SEC reserves for accounting purposes makes our results more comparable with those of our major competitors. |
| b | UK area includes the UK-based international activities of Refining and Marketing. |
Back to Contents
10 Impairment and losses on sale of businesses and fixed assets
| | | | | | | $ million | |
|
|
| | | 2007 | | 2006 | | 2005 | |
|
| Impairment losses | | | | | | |
| | Exploration and Production | 292 | | 137 | | 266 | |
| | Refining and Marketing | 1,186 | | 155 | | 93 | |
| | Gas, Power and Renewables | 40 | | 100 | | – | |
| | Other businesses and corporate | 43 | | 69 | | 59 | |
|
| | | 1,561 | | 461 | | 418 | |
|
| Impairment reversals | | | | | | |
| | Exploration and Production | (237 | ) | (340 | ) | – | |
|
| | | (237 | ) | (340 | ) | – | |
|
| Loss on sale of fixed assets | | | | | | |
| | Exploration and Production | 42 | | 195 | | 39 | |
| | Refining and Marketing | 313 | | 228 | | 64 | |
| | Other businesses and corporate | – | | 5 | | 6 | |
|
| | | 355 | | 428 | | 109 | |
| Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations | – | | 184 | | 591 | |
|
| | | 1,679 | | 733 | | 1,118 | |
| Innovene operations | – | | (184 | ) | (650 | ) |
|
| Continuing operations | 1,679 | | 549 | | 468 | |
|
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 11% (2006 10% and 2005 10%). This discount rate is derived from the group’s post-tax weighted average cost of capital. In some cases the group’s pre-tax discount rate may be adjusted to account for political risk in the country where the asset is located.
Exploration and Production
During 2007, the Exploration and Production segment recognized impairment losses of $292 million. The main elements were a charge of $112 million relating to the cancellation of the DF1 project in Scotland, a $103 million partner loan write-off as a result of unsuccessful drilling in the West Shmidt licence block in Sakhalin and a $52 million write-off of the Whitney Canyon gas plant in US Lower 48 driven by management’s decision to abandon this facility. In addition, there were several individually insignificant impairment charges, triggered by downward reserves revisions, amounting to $25 million in total.
These charges were largely offset by reversals of previously recognized impairment charges amounting to $237 million. Of this total, $208 million resulted from a reassessment of the decommissioning liability for damaged platforms in the Gulf of Mexico Shelf. The remaining $29 million related to other individually insignificant impairment reversals, resulting from favourable revisions to the estimates used in determining the assets’ recoverable amounts.
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 recognized. 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.
Refining and Marketing
The main component of the 2007 impairment charge arose because of a decision to sell our company-owned and company-operated sites in the US resulting in a $610 million write-down of the carrying amount of the sites to fair value less costs to sell. Following a decision to sell certain assets at our Acetyls plant in Hull, UK, we wrote down the carrying amount of these assets to fair value less costs to sell leading to an impairment charge of $186 million. Changing marketing conditions led to impairments in Samsung Petrochemical Company, to fair value less costs to sell, and in China American Petrochemical Company amounting in total to $165 million. The balance relates principally to the write-downs of assets elsewhere in the segment portfolio.
During 2006, certain assets in our Retail and Aromatics & 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.
Back to Contents
10 Impairment and losses on sale of businesses and fixed assets continued
Gas, Power and Renewables
There were no significant impairments in 2007.
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 ongoing operational costs.
Other businesses and corporate
There were no significant impairments in 2007.
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.
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 included increases in decommissioning liability estimates associated with the hurricane-damaged fields that were divested during the year.
Refining and Marketing
For 2007, the principal transactions contributing to the loss were related to the decision to withdraw from the company-owned and company-operated channel of trade in the US and retail churn. Retail churn is the overall process of acquiring and disposing of retail sites by which the group aims to improve the quality and mix of its portfolio of service stations.
For 2006, the principal transactions contributing to the loss were retail churn.
11 Impairment of goodwill
| | | | $ million | |
|
| Goodwill at 31 December | 2007 | | 2006 | |
|
| Exploration and Production | 4,247 | | 4,282 | |
| Refining and Marketing | 6,626 | | 6,390 | |
| Gas, Power and Renewables | 133 | | 108 | |
|
| | 11,006 | | 10,780 | |
|
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 the following cash-generating units, namely Refining, Retail, Lubricants and Other.
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 11% (2006 10%). This discount rate is derived from the group’s post-tax weighted average cost of capital. In some cases the group’s pre-tax discount rate may be adjusted to account for political risk in the country where the asset is located.
The five year business segment plans, which are approved on an annual basis by senior management, are the source of 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 in 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 $90 per barrel in 2008, $86 per barrel in 2009, $84 per barrel in 2010, $84 per barrel in 2011, $84 per barrel in 2012 and $60 per barrel in 2013 and beyond (2006 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). Similarly, the group’s assumption for Henry Hub natural gas prices is an average of $7.87 per mmBtu in 2008, $8.33 per mmBtu in 2009, $8.26 per mmBtu in 2010, $8.12 per mmBtu in 2011, $8.00 per mmBtu in 2012 and $7.50 per mmBtu in 2013 and beyond (2006 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). These prices are adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas.
Back to Contents
11 Impairment of goodwill continued
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 2007 using data that was appropriate at that time. As permitted by IAS 36, the detailed calculations made in 2005 and 2006 were used for the 2007 impairment test on the goodwill in each geographical segment as the criteria of IAS 36 were considered to be satisfied: the excess of the recoverable amount over the carrying amount was substantial for Rest of World in 2005 and the UK and the US in 2006; 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.
The following table shows the carrying value of the goodwill allocated to each of the regions of the Exploration and Production segment and, where required, 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.
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 (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.
In the prior year, it was estimated that the long-term price of Brent that would cause the total recoverable amount to be equal to the total carrying amount of 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, and that no reasonably possible change in oil and gas prices would cause the headroom in Rest of World to be reduced to zero. Since that time, oil prices have continued to rise and the group has increased its price assumptions as disclosed above. Management now believes that no reasonably possible change in oil and gas prices would cause the headroom in any of the geographical segments 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 that would reduce the group’s headroom to zero.
| | | | | $ million |
|
| | | | | 2007 |
|
| | | | Rest of | |
| UK | US | World | Total |
|
| Goodwill | 341 | 3,391 | 515 | 4,247 |
|
| | | | | $ million |
|
| | | | | 2006 |
|
| | | | Rest of | |
| | UK | US | World | Total |
|
| Goodwill | 341 | 3,426 | 515 | 4,282 |
| Excess of recoverable amount over carrying amount | 7,886 | 28,856 | n/a | n/a |
|
Refining and Marketing
For all cash-generating units, the cash flows for the next five years are derived from the five-year business segment plan. The cost inflation rate is assumed to be 2.5% (2006 2.5%) throughout the period. In determining the value in use for each of the cash-generating units, cash flows for a period of 10 years have been discounted and aggregated with its terminal value.
Refining
Cash flows beyond the five-year period are extrapolated using a 2% growth rate (2006 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 average value assigned to the gross margin during the plan period is based on a $7.90 per barrel global indicator margin (GIM), which is then adjusted for specific refinery configurations (2006 $7.25 per barrel). The average value assigned to the production volume is 850mmbbl a year (2006 850mmbbl) over the plan period. The value assigned to the terminal value assumption is 6 times earnings (2006 6 times), which is indicative of similar assets in the current market. These key assumptions reflect past experience and are consistent with external sources.
The Refining unit’s recoverable amount exceeds its carrying amount by $11.4 billion. Based on sensitivity analysis, it is estimated that if the GIM changes by $1 per barrel, the Refining unit’s value in use changes by $7.6 billion and, if there was an adverse change in the GIM of $1.50 per barrel, the recoverable amount of the Refining unit would equal its carrying amount. If the volume assumption changes by 5%, the Refining unit’s value in use changes by $5.1 billion and, if there was an adverse change in Refining volumes of 95mmbbl a year, the recoverable amount of the Refining unit would equal its carrying amount. If the multiple of earnings used in the terminal value changes by 1 then the Refining unit’s value in use changes by $1.7 billion. Management believes no reasonably possible change in the multiple of earnings used in the terminal value would lead to the Refining unit’s value in use being equal to its carrying amount.
Back to Contents
11 Impairment of goodwill continued
Retail
Cash flows beyond the five-year period are extrapolated using a 0.9% growth rate (2006 assumption was 1.3%) 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, marketing volumes, the terminal value and discount rate. The weighted average Retail fuel margin used in the plan was 3.1 cents per litre (2006 2.6 cents per litre). The value assigned to the unit gross margin varies between markets. For the purpose of planning, each market develops a gross margin based upon the different income streams within the market and other market-specific factors. In 2007, all markets were provided with the same reference price, which was then adjusted for specific market factors and income streams in each operating unit. The gross margin assumption quoted this year is the weighted average of the margins used by each operating unit. The comparative has been prepared on the same basis. In the prior year each operating unit was provided with a market-specific reference price as a starting point. The weighted average of these assumptions was disclosed as the gross margin assumption in the prior year. The average value assigned to the marketing volume assumption is 125 billion litres a year (2006 134 billion litres a year). The unit gross margin assumptions increase on average by 1% a year over the plan period and marketing volume assumptions grow by an average of 1% a year over the plan period. The value assigned to the terminal value assumption is 6.5 times earnings (2006 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 $4.1 billion. Based on sensitivity analysis, it is estimated that if there is an adverse change in the weighted average fuel 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 $1.8 billion and, if there is an adverse change in marketing volumes of 14 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 $0.8 billion and, if the multiple of earnings falls to 1 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 $0.9 billion and, if the discount rate increases to 17%, the value in use of the Retail unit would equal its carrying amount.
Lubricants
Cash flows beyond the five-year period are extrapolated using a 3% margin growth rate (2006 3%), which is lower than the long-term average growth rate for the first five 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 margin and sales volumes over the plan period are 65 cents per litre (2006 53 cents per litre) and 3.3 billion litres a year (2006 3.5 billion litres) respectively. These key assumptions reflect past experience.
The Lubricants unit’s recoverable amount exceeds its carrying amount by $5.0 billion. Based on sensitivity analysis, it is estimated that if there is an adverse change in the operating margin of 14 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 $1.2 billion and, if there is an adverse change in Lubricants sales volumes of 700 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 $1.2 billion and, if the discount rate increases to 19% the value in use of the Lubricants unit would equal its carrying amount.
| | | | | | | | | | $ million | |
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| | | | | | | | | | 2007 | |
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| | Refining | | Retail | | Lubricants | | Other | | Total | |
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|
|
| Goodwill | 1,515 | | 827 | | 4,175 | | 109 | | 6,626 | |
| Excess of recoverable amount over carrying amount | 11,443 | | 4,062 | | 5,028 | | n/a | | n/a | |
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| | | | | | | | | | | |
| | | | | | | | | | $ million | |
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| | | | | | | | | | 2006 | |
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| | Refining | | Retail | | Lubricants | | Other | | Total | |
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|
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| Goodwill | 1,328 | | 841 | | 4,098 | | 123 | | 6,390 | |
| Excess of recoverable amount over carrying amount | n/a | | 2,100 | | 2,012 | | n/a | | n/a | |
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Back to Contents
12 Distribution and administration expenses
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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| Distribution | 14,028 | | 13,174 | | 13,187 | |
| Administration | 1,343 | | 1,273 | | 1,325 | |
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|
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| | 15,371 | | 14,447 | | 14,512 | |
| Innovene operations | – | | – | | (806 | ) |
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|
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| Continuing operations | 15,371 | | 14,447 | | 13,706 | |
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13 Currency exchange gains and losses
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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|
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| Currency exchange (gains) losses (credited) charged to income | (189 | ) | 222 | | 94 | |
| Innovene operations | – | | – | | (80 | ) |
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| Continuing operations | (189 | ) | 222 | | 14 | |
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14 Research and development
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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| Expenditure on research and development | 566 | | 395 | | 502 | |
| Innovene operations | – | | – | | (128 | ) |
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| Continuing operations | 566 | | 395 | | 374 | |
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Back to Contents
15 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 future minimum lease payments are excluded from the information given below.
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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| Minimum lease payments | 4,152 | | 3,647 | | 2,743 | |
| Contingent rentals | 105 | | 13 | | (6 | ) |
| Sub-lease rentals | (191 | ) | (131 | ) | (114 | ) |
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| | 4,066 | | 3,529 | | 2,623 | |
| Innovene operations | – | | – | | (49 | ) |
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| Continuing operations | 4,066 | | 3,529 | | 2,574 | |
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In addition to the above, 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 2007, $1,300 million (2006 $895 million) of the cost for the year has been capitalized.
The future minimum lease payments at 31 December, before deducting related rental income from operating sub-leases of $618 million (2006 $626 million and 2005 $718 million), are shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor, the future minimum lease payments are based on the factor as at inception of the lease.
| | | | $ million | |
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| Future minimum lease payments | 2007 | | 2006 | |
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|
|
| Payable within | | | | |
| 1 year | 3,780 | | 3,428 | |
| 2 to 5 years | 7,660 | | 8,440 | |
| Thereafter | 5,498 | | 5,684 | |
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|
|
|
|
| | 16,938 | | 17,552 | |
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|
|
|
The following additional disclosures represent the net operating lease expense and net future minimum lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint venture partners.
Where BP is not the operator of a jointly controlled asset, operating lease costs and future minimum lease payments are excluded from the information given below.
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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|
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| Minimum lease payments | 3,100 | | 2,924 | | 1,847 | |
| Contingent rentals | 80 | | 13 | | (6 | ) |
| Sub-lease rentals | (183 | ) | (131 | ) | (110 | ) |
|
|
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|
|
|
|
| | 2,997 | | 2,806 | | 1,731 | |
| Innovene operations | – | | – | | (49 | ) |
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|
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| Continuing operations | 2,997 | | 2,806 | | 1,682 | |
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| | | | | |
| | | | $ million | |
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| Future minimum lease payments | 2007 | | 2006 | |
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|
|
| Payable within | | | | |
| 1 year | 2,826 | | 2,732 | |
| 2 to 5 years | 6,519 | | 7,290 | |
| Thereafter | 5,050 | | 5,221 | |
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|
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|
| | 14,395 | | 15,243 | |
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|
|
The group enters into operating leases of ships, plant and machinery, commercial vehicles and land and buildings. 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 |
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|
Back to Contents
The group has entered into a number of structured operating leases for ships and in most cases the lease rental payments vary with market interest rates. The variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is treated as contingent rental expense, but the amounts of such 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.
The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Exploration and Production segment. In some cases, drilling rig lease rental rates are adjusted periodically to market rates that are influenced by oil prices and may be significantly different from the rates at the inception of the lease. Differences between the rate paid and rate at inception of the lease are treated as contingent rental expense.
Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in the land and buildings category.
The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of ships and buildings allow for renewals at BP’s option.
16 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 | |
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|
|
| | 2007 | | 2006 | | 2005 | |
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|
|
| Exploration and evaluation costs | | | | | | |
| Exploration expenditure written off | 347 | | 624 | | 305 | |
| Other exploration costs | 409 | | 421 | | 379 | |
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|
|
|
|
|
|
| Exploration expense for the year | 756 | | 1,045 | | 684 | |
|
| Intangible assets – exploration expenditure | 5,252 | | 4,110 | | 4,008 | |
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|
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|
|
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| Net assets | 5,252 | | 4,110 | | 4,008 | |
|
| Capital expenditure | 2,000 | | 1,537 | | 950 | |
|
| Net cash used in operating activities | 409 | | 421 | | 379 | |
| Net cash used in investing activities | 2,000 | | 1,498 | | 950 | |
|
17 Auditors’ remuneration
| | | | | | $ million | |
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|
|
|
|
|
|
| Fees – Ernst & Young | 2007 | | 2006 | | 2005 | |
|
|
|
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|
|
|
| Fees payable to the company’s auditors for the audit of the company’s accountsa | 18 | | 15 | | 19 | |
| Fees payable to the company’s auditors and its associates for other services | | | | | | |
| Audit of the company’s subsidiaries pursuant to legislation | 31 | | 31 | | 34 | |
| Other services pursuant to legislation | 14 | | 15 | | 6 | |
|
|
|
|
|
|
|
| | 63 | | 61 | | 59 | |
| Tax services | 2 | | 1 | | 10 | |
| Services relating to corporate finance transactions | 1 | | 2 | | 3 | |
| All other services | 8 | | 9 | | 23 | |
| Audit fees in respect of the BP pension plans | 1 | | – | | 1 | |
|
|
|
|
|
|
|
| | 75 | | 73 | | 96 | |
| Innovene operations | – | | – | | (9 | ) |
|
|
|
|
|
|
|
| Continuing operations | 75 | | 73 | | 87 | |
|
| 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 2007 include $7 million of additional fees for 2006 (2006 includes $5 million of additional fees for 2005 and 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, employee tax services and tax advisory 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 with that of other potential service providers. These services are for a fixed term.
Back to Contents
18 Finance costs
| | | | | | $ million | |
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|
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|
|
|
| | 2007 | | 2006 | | 2005 | |
|
|
| Bank loans and overdrafts | 89 | | 130 | | 44 | |
| Other loans | 1,302 | | 1,020 | | 828 | |
| Finance leases | 42 | | 46 | | 38 | |
|
|
| Interest payable | 1,433 | | 1,196 | | 910 | |
| Capitalized at 5.70% (2006 5.25% and 2005 4.25%)a | (323 | ) | (478 | ) | (351 | ) |
| Early redemption of borrowings and finance leases | – | | – | | 57 | |
|
|
| | 1,110 | | 718 | | 616 | |
|
| a | Tax relief on capitalized interest is $81 million (2006 $182 million and 2005 $123 million). |
19 Other finance income and expense
| | | | | | $ million | |
|
|
|
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|
|
|
| | 2007 | | 2006 | | 2005 | |
|
|
|
|
|
|
|
| Interest on pension and other post-retirement benefit plan liabilities | 2,203 | | 1,940 | | 2,022 | |
| Expected return on pension and other post-retirement benefit plan assets | (2,855 | ) | (2,410 | ) | (2,138 | ) |
|
|
|
|
|
|
|
| Interest net of expected return on plan assets | (652 | ) | (470 | ) | (116 | ) |
| Unwinding of discount on provisions | 283 | | 245 | | 201 | |
| Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP | – | | 23 | | 57 | |
|
|
|
|
|
|
|
| | (369 | ) | (202 | ) | 142 | |
| Innovene operations | – | | – | | 3 | |
|
|
|
|
|
|
|
| Continuing operations | (369 | ) | (202 | ) | 145 | |
|
20 Taxation
| | | | | | $ million | |
|
|
|
|
|
|
|
| Tax on profit | 2007 | | 2006 | | 2005 | |
|
|
|
|
|
|
|
| Current tax | | | | | | |
| Charge for the year | 10,006 | | 11,199 | | 10,511 | |
| Adjustment in respect of prior years | (171 | ) | 442 | | (977 | ) |
|
|
|
|
|
|
|
| | 9,835 | | 11,641 | | 9,534 | |
| Innovene operations | – | | 159 | | (910 | ) |
|
|
|
|
|
|
|
| Continuing operations | 9,835 | | 11,800 | | 8,624 | |
|
|
|
|
|
|
|
| Deferred tax | | | | | | |
| Origination and reversal of temporary differences in the current year | 671 | | 1,956 | | 164 | |
| Adjustment in respect of prior years | (64 | ) | (1,240 | ) | (450 | ) |
|
|
|
|
|
|
|
| | 607 | | 716 | | (286 | ) |
| Innovene operations | – | | – | | 950 | |
|
|
|
|
|
|
|
| Continuing operations | 607 | | 716 | | 664 | |
|
|
|
|
|
|
|
| Tax on profit from continuing operations | 10,442 | | 12,516 | | 9,288 | |
|
| Tax on profit from continuing operations may be analysed as follows: | | | | | | |
|
|
|
|
|
|
|
| Current tax charge | | | | | | |
| UK | 2,067 | | 2,657 | | 880 | |
| Overseas | 7,768 | | 9,143 | | 7,744 | |
|
|
|
|
|
|
|
| | 9,835 | | 11,800 | | 8,624 | |
|
|
|
|
|
|
|
| Deferred tax charge | | | | | | |
| UK | 216 | | 500 | | (489 | ) |
| Overseas | 391 | | 216 | | 1,153 | |
|
|
|
|
|
|
|
| | 607 | | 716 | | 664 | |
|
|
|
|
|
|
|
| Total | | | | | | |
| UK | 2,283 | | 3,157 | | 391 | |
| Overseas | 8,159 | | 9,359 | | 8,897 | |
|
|
|
|
|
|
|
| | 10,442 | | 12,516 | | 9,288 | |
|
Back to Contents
20 Taxation continued
| | | | | | $ million | |
|
|
|
|
|
|
|
| Tax included in the statement of recognized income and expense | 2007 | | 2006 | | 2005 | |
|
|
|
|
|
|
|
| Current tax | (178 | ) | (51 | ) | 45 | |
| Deferred tax | 241 | | 985 | | 214 | |
|
|
|
|
|
|
|
| | 63 | | 934 | | 259 | |
|
| This comprises: | | | | | | |
|
|
|
|
|
|
|
| Currency translation differences | (139 | ) | 201 | | (11 | ) |
| 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 | 427 | | 820 | | 356 | |
| Share-based payments | (213 | ) | (26 | ) | – | |
| Cash flow hedges | (26 | ) | 47 | | (63 | ) |
| Available-for-sale investments | 14 | | (108 | ) | 72 | |
|
|
|
|
|
|
|
| | 63 | | 934 | | 259 | |
|
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 | |
|
|
|
|
|
|
|
| | 2007 | | 2006 | | 2005 | |
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 31,611 | | 35,142 | | 31,421 | |
|
| Tax on profit from continuing operations | 10,442 | | 12,516 | | 9,288 | |
|
|
|
|
|
|
|
| Effective tax rate | 33 | % | 36 | % | 30 | % |
|
| % of profit before taxation from continuing operations | |
|
|
|
|
|
|
|
| UK statutory corporation tax rate | 30 | | 30 | | 30 | |
| Increase (decrease) resulting from | | | | | | |
| UK supplementary and overseas taxes at higher rates | 7 | | 11 | | 9 | |
| Tax reported in equity-accounted entities | (2 | ) | (3 | ) | (3 | ) |
| Adjustments in respect of prior years | (1 | ) | (2 | ) | (3 | ) |
| Restructuring benefits | – | | – | | (1 | ) |
| Current year losses unrelieved (prior year losses utilized) | (1 | ) | (1 | ) | (3 | ) |
| Other | – | | 1 | | 1 | |
|
|
|
|
|
|
|
| Effective tax rate | 33 | | 36 | | 30 | |
|
|
|
|
|
|
|
| Deferred tax | | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | Income statement | | | | | | Balance sheet | |
|
|
|
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|
|
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|
|
| | 2007 | | 2006 | | 2005 | | | | 2007 | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
| Deferred tax liability | | | | | | | | | | | | |
| Depreciation | (54 | ) | 1,484 | | (778 | ) | | | 21,757 | | 21,463 | |
| Pension plan surplus | 127 | | 173 | | 170 | | | | 2,136 | | 1,733 | |
| Other taxable temporary differences | 1,371 | | 417 | | 887 | | | | 5,998 | | 4,895 | |
|
|
|
|
|
|
|
|
|
|
|
| | 1,444 | | 2,074 | | 279 | | | | 29,891 | | 28,091 | |
|
|
|
|
|
|
|
|
|
|
|
| Deferred tax asset | | | | | | | | | | | | |
| Petroleum revenue tax | 139 | | 4 | | 121 | | | | (325 | ) | (457 | ) |
| Pension plan and other post-retirement benefit plan deficits | (72 | ) | 71 | | 220 | | | | (1,545 | ) | (1,824 | ) |
| Decommissioning, environmental and other provisions | (759 | ) | (615 | ) | (329 | ) | | | (3,746 | ) | (2,960 | ) |
| Derivative financial instruments | 450 | | (115 | ) | (629 | ) | | | (541 | ) | (974 | ) |
| Tax credit and loss carry forward | (466 | ) | 220 | | (245 | ) | | | (1,822 | ) | (1,118 | ) |
| Other deductible temporary differences | (129 | ) | (923 | ) | 297 | | | | (2,697 | ) | (2,642 | ) |
|
|
|
|
|
|
|
|
|
|
|
| | (837 | ) | (1,358 | ) | (565 | ) | | | (10,676 | ) | (9,975 | ) |
|
|
|
|
|
|
|
|
|
|
|
| Net deferred tax liability | 607 | | 716 | | (286 | ) | | | 19,215 | | 18,116 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| Analysis of movements during the year | | | | | | | | | 2007 | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
| At 1 January | | | | | | | | | 18,116 | | 16,258 | |
| Exchange adjustments | | | | | | | | | 42 | | 175 | |
| Charge for the year on ordinary activities | | | | | | | | | 607 | | 716 | |
| Charge for the year in the statement of recognized income and expense | | | | | | | | | 241 | | 985 | |
| Acquisitions | | | | | | | | | 199 | | – | |
| Other movements | | | | | | | | | 10 | | (18 | ) |
|
|
|
|
|
|
|
|
|
|
|
| At 31 December | | | | | | | | | 19,215 | | 18,116 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
Back to Contents
20 Taxationcontinued
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 rate of UK corporation tax. 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 2007 effective tax rate for the group reflects the impact of the use of capital and other losses in the UK and mainland Europe and audit closure of a variety of worldwide issues. The enactment of a 2% reduction in the rate of UK corporation tax on profits arising from activities outside the North Sea reduced the tax charge by $189 million.
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 2007 has been to reduce the reported effective tax rate by around 2%. This effect is expected to continue for the foreseeable future assuming similar income levels from the entities.
| At 31 December 2007, 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 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 taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where the timing of the reversal of the temporary differences can be controlled by the group and it is probable that the temporary differences will not reverse in the foreseeable future. |
| At 31 December 2007, 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 in a 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 group has around $5.0 billion (2006 $4.9 billion) of carry-forward tax losses, predominantly in Europe, which would be available to offset against future taxable income. These tax losses do not have a fixed expiry date. At the end of 2007, a net deferred tax asset of $286 million was recognized on these losses (2006 $216 million). The gross deferred tax asset recognized for the losses was $972 million (2006 $680 million), of which $686 million (2006 $458 million) was offset by deferred tax liabilities. Deferred tax assets are recognized only to the extent that it is considered more likely than not that suitable taxable income will arise. |
| At the end of 2007, the group had around $4.1 billion (2006 $2.0 billion) of unused tax credits in the UK and US, in respect of which no net deferred tax assets have been recognized. A gross deferred tax asset of $820 million has been recognized in 2007 for these credits (2006 $459 million), which is offset by a gross deferred tax liability associated with unremitted profits from overseas entities in jurisdictions with a lower tax rate than the UK. The UK tax credits do not have a fixed expiry date. The US tax credits expire ten years after generation. In 2007, $411 million of tax credits were utilized (2006 $828 million and 2005 $774 million). |
| The major components of temporary differences at the end of the current year are tax depreciation, US inventory holding gains (classified under other taxable temporary differences) and provisions. |
21 Dividends
| | | pence per share | | | cents per share | | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | | 2007 | | 2006 | | 2005 | | 2007 | | 2006 | | 2005 | |
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| Dividends announced and paid | | | | | | | | | | | | | | | | | | |
| Preference shares | | | | | | | | | | | | | 2 | | 2 | | 2 | |
| Ordinary shares | | | | | | | | | | | | | | | | | | |
| March | 5.258 | | 5.288 | | 4.522 | | 10.325 | | 9.375 | | 8.500 | | 2,000 | | 1,922 | | 1,823 | |
| June | 5.151 | | 5.251 | | 4.450 | | 10.325 | | 9.375 | | 8.500 | | 1,983 | | 1,893 | | 1,808 | |
| September | 5.278 | | 5.324 | | 5.119 | | 10.825 | | 9.825 | | 8.925 | | 2,065 | | 1,943 | | 1,871 | |
| December | 5.308 | | 5.241 | | 5.061 | | 10.825 | | 9.825 | | 8.925 | | 2,056 | | 1,926 | | 1,855 | |
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| | 20.995 | | 21.104 | | 19.152 | | 42.300 | | 38.400 | | 34.850 | | 8,106 | | 7,686 | | 7,359 | |
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| Dividend announced per ordinary share, payable in March 2008 | 6.813 | | – | | – | | 13.525 | | – | | – | | 2,554 | | – | | – | |
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The group does not account for dividends until they are paid. The accounts for the year ended 31 December 2007 do not reflect the dividend announced on 5 February 2008 and payable in March 2008; this will be treated as an appropriation of profit in the year ended 31 December 2008.
Back to Contents
22 Earnings per ordinary share
| | | | | | cents per share | |
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| | 2007 | | 2006 | | 2005 | |
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| Basic earnings per share | 108.76 | | 111.41 | | 104.25 | |
| Diluted earnings per share | 107.84 | | 110.56 | | 103.05 | |
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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 weighted average number of shares outstanding during the year is adjusted for the number of shares that would be issued in connection with employee share-based payment plans using the treasury stock method. In addition, for 2006 and 2005, the profit attributable to ordinary shareholders has been adjusted for the unwinding of the discount on the deferred consideration for the acquisition of our interest in TNK-BP and the weighted average number of shares outstanding during the year has been adjusted for the number of shares to be issued for the deferred consideration for the acquisition of our interest in TNK-BP.
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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| Profit from continuing operations attributable to BP shareholders | 20,845 | | 22,340 | | 21,842 | |
| Less dividend requirements on preference shares | 2 | | 2 | | 2 | |
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| Profit from continuing operations attributable to BP ordinary shareholders | 20,843 | | 22,338 | | 21,840 | |
| Profit (loss) from discontinued operations | – | | (25 | ) | 184 | |
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| | 20,843 | | 22,313 | | 22,024 | |
| Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP (net of tax) | – | | 16 | | 40 | |
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| Diluted profit for the year attributable to BP ordinary shareholders | 20,843 | | 22,329 | | 22,064 | |
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| | | | | | shares thousand | |
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| | 2007 | | 2006 | | 2005 | |
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| Basic weighted average number of ordinary shares | 19,163,389 | | 20,027,527 | | 21,125,902 | |
| Potential dilutive effect of ordinary shares issuable under employee share schemes | 163,486 | | 109,813 | | 87,743 | |
| Potential dilutive effect of ordinary shares issuable as consideration for BP’s interest in the TNK-BP joint venture | – | | 58,118 | | 197,802 | |
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| | 19,326,875 | | 20,195,458 | | 21,411,447 | |
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The number of ordinary shares outstanding at 31 December 2007, excluding treasury shares, was 18,922,785,598. Between 31 December 2007 and 19 February 2008, the latest practicable date before the completion of these financial statements, there has been a net decrease of 44,539,157 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 schemes was 154,039,764 at 31 December 2007. There has been a decrease of 10,797,601 in the number of potential ordinary shares between 31 December 2007 and 19 February 2008.
Earnings (loss) per share for the discontinued operations is derived from the net profit (loss) attributable to ordinary shareholders from discontinued operations of $nil (2006 $25 million loss and 2005 $184 million profit), divided by the weighted average number of ordinary shares for both basic and diluted amounts as shown above.
Back to Contents
23 Property, plant and equipment
| | | | | | | | | | | | | | | | | $ million | |
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| | | Land and | | | | | | Plant, | | Fixtures, fittings | | | | Oil depots, | | | |
| | | land | | | | Oil and gas | | machinery | | and office | | | | storage tanks and | | | |
| | | improvements | | Buildings | | properties | | and equipment | | equipment | | Transportation | | service stations | | Total | |
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| Cost | | | | | | | | | | | | | | | | |
| | At 1 January 2007 | 4,442 | | 3,129 | | 123,493 | | 32,203 | | 3,006 | | 11,930 | | 11,076 | | 189,279 | |
| | Exchange adjustments | 271 | | 148 | | 22 | | 1,182 | | 73 | | 32 | | 733 | | 2,461 | |
| | Acquisitions | – | | – | | – | | 910 | | – | | – | | – | | 910 | |
| | Additions | 78 | | 171 | | 12,107 | | 3,662 | | 466 | | 181 | | 643 | | 17,308 | |
| | Transfers | – | | – | | 422 | | – | | – | | – | | – | | 422 | |
| | Reclassified as assets held for sale | (16 | ) | – | | – | | (1,114 | ) | – | | – | | – | | (1,130 | ) |
| | Deletions | (259 | ) | (298 | ) | (1,429 | ) | (478 | ) | (376 | ) | (277 | ) | (1,042 | ) | (4,159 | ) |
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| At 31 December 2007 | 4,516 | | 3,150 | | 134,615 | | 36,365 | | 3,169 | | 11,866 | | 11,410 | | 205,091 | |
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| Depreciation | | | | | | | | | | | | | | | | |
| | At 1 January 2007 | 675 | | 1,470 | | 66,189 | | 16,189 | | 1,762 | | 6,876 | | 5,119 | | 98,280 | |
| | Exchange adjustments | 25 | | 89 | | 19 | | 556 | | 45 | | 16 | | 299 | | 1,049 | |
| | Charge for the year | 52 | | 98 | | 7,370 | | 1,266 | | 341 | | 373 | | 741 | | 10,241 | |
| | Impairment losses | 86 | | 62 | | 189 | | 236 | | 9 | | 14 | | 643 | | 1,239 | |
| | Impairment reversals | – | | – | | (237 | ) | – | | – | | – | | – | | (237 | ) |
| | Reclassified as assets held for sale | (9 | ) | – | | – | | (486 | ) | – | | – | | – | | (495 | ) |
| | Deletions | (111 | ) | (186 | ) | (1,044 | ) | (344 | ) | (337 | ) | (153 | ) | (800 | ) | (2,975 | ) |
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| At 31 December 2007 | 718 | | 1,533 | | 72,486 | | 17,417 | | 1,820 | | 7,126 | | 6,002 | | 107,102 | |
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| Net book amount at 31 December 2007 | 3,798 | | 1,617 | | 62,129 | | 18,948 | | 1,349 | | 4,740 | | 5,408 | | 97,989 | |
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| Cost | | | | | | | | | | | | | | | | |
| | At 1 January 2006 | 4,576 | | 2,835 | | 114,413 | | 30,341 | | 2,247 | | 13,196 | | 11,100 | | 178,708 | |
| | Exchange adjustments | 255 | | 239 | | 72 | | 1,028 | | 138 | | 27 | | 517 | | 2,276 | |
| | Acquisitions | – | | – | | – | | 16 | | – | | – | | – | | 16 | |
| | Additions | 81 | | 381 | | 11,264 | | 2,146 | | 841 | | 22 | | 918 | | 15,653 | |
| | Transfersa | – | | – | | (628 | ) | – | | (1 | ) | – | | – | | (629 | ) |
| | Reclassified as assets held for sale | (15 | ) | (1 | ) | – | | (842 | ) | – | | (1 | ) | (47 | ) | (906 | ) |
| | Deletions | (455 | ) | (325 | ) | (1,628 | ) | (486 | ) | (219 | ) | (1,314 | ) | (1,412 | ) | (5,839 | ) |
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| At 31 December 2006 | 4,442 | | 3,129 | | 123,493 | | 32,203 | | 3,006 | | 11,930 | | 11,076 | | 189,279 | |
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| Depreciation | | | | | | | | | | | | | | | | |
| | At 1 January 2006 | 709 | | 1,437 | | 62,192 | | 14,978 | | 1,450 | | 7,034 | | 4,961 | | 92,761 | |
| | 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 | ) | (1,048 | ) | (173 | ) | (212 | ) | (471 | ) | (708 | ) | (3,067 | ) |
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| At 31 December 2006 | 675 | | 1,470 | | 66,189 | | 16,189 | | 1,762 | | 6,876 | | 5,119 | | 98,280 | |
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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 | |
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| Assets held under finance leases at | | | | | | | | | | | | | | | | |
| | net book amount included above | | | | | | | | | | | | | | | | |
| | At 31 December 2007 | – | | 17 | | 155 | | 185 | | – | | 11 | | 24 | | 392 | |
| | At 31 December 2006 | 5 | | 18 | | 42 | | 341 | | 1 | | 9 | | 29 | | 445 | |
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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 2007 | 7,851 | | 3,328 | | 4,523 | |
| At 31 December 2006 | 6,391 | | 2,558 | | 3,833 | |
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| Assets under construction included above | | | | | | |
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| At 31 December 2007 | | | | | 18,658 | |
| At 31 December 2006 | | | | | 17,800 | |
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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
24 Goodwill
| | | | $ million | |
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| | 2007 | | 2006 | |
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| Cost and net book amount | | | | |
| At 1 January | 10,780 | | 10,371 | |
| Exchange adjustments | 126 | | 524 | |
| Acquisitions | 270 | | 64 | |
| Reclassified as assets held for sale | (90 | ) | (60 | ) |
| Deletions | (80 | ) | (119 | ) |
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| At 31 December | 11,006 | | 10,780 | |
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25 Intangible assets
| | | | | | | | | | | | $ million | |
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| | | | | | 2007 | | | | | | 2006 | |
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| | Exploration | | Other | | | | Exploration | | Other | | | |
| | expenditure | | intangibles | | Total | | expenditure | | intangibles | | Total | |
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| Cost | | | | | | | | | | | | |
| At 1 January | 4,590 | | 2,128 | | 6,718 | | 4,661 | | 1,740 | | 6,401 | |
| Exchange adjustments | 3 | | 49 | | 52 | | 2 | | 50 | | 52 | |
| Acquisitions | – | | 35 | | 35 | | – | | 187 | | 187 | |
| Additions | 2,000 | | 548 | | 2,548 | | 1,537 | | 378 | | 1,915 | |
| Transfersa | (506 | ) | – | | (506 | ) | (698 | ) | – | | (698 | ) |
| Deletions | (450 | ) | (130 | ) | (580 | ) | (912 | ) | (227 | ) | (1,139 | ) |
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| At 31 December | 5,637 | | 2,630 | | 8,267 | | 4,590 | | 2,128 | | 6,718 | |
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| Amortization | | | | | | | | | | | | |
| At 1 January | 480 | | 992 | | 1,472 | | 653 | | 976 | | 1,629 | |
| Exchange adjustments | – | | 25 | | 25 | | – | | 20 | | 20 | |
| Charge for the year | 347 | | 338 | | 685 | | 624 | | 217 | | 841 | |
| Transfers | – | | – | | – | | (2 | ) | – | | (2 | ) |
| Impairment losses | – | | – | | – | | 109 | | – | | 109 | |
| Deletions | (442 | ) | (125 | ) | (567 | ) | (904 | ) | (221 | ) | (1,125 | ) |
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| At 31 December | 385 | | 1,230 | | 1,615 | | 480 | | 992 | | 1,472 | |
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| Net book amount at 31 December | 5,252 | | 1,400 | | 6,652 | | 4,110 | | 1,136 | | 5,246 | |
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| a | Included in transfers of exploration expenditure is $84 million (2006 $240 million) transferred to equity-accounted investments. |
| |
Back to Contents
26 Investments in jointly controlled entities
The significant jointly controlled entities of the BP group at 31 December 2007 are shown in Note 46. 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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| | | | 2007 | | | 2006 | | | | 2005 | |
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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 | 19,463 | 7,245 | 26,708 | 17,863 | 6,119 | 23,982 | | 15,122 | 4,255 | 19,377 | |
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| Profit before interest and taxation | 3,743 | 1,299 | 5,042 | 4,616 | 1,218 | 5,834 | | 3,817 | 779 | 4,596 | |
| Finance costs and other finance expense | 264 | 176 | 440 | 192 | 169 | 361 | | 128 | 104 | 232 | |
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| Profit before taxation | 3,479 | 1,123 | 4,602 | 4,424 | 1,049 | 5,473 | | 3,689 | 675 | 4,364 | |
| Taxation | 993 | 259 | 1,252 | 1,467 | 260 | 1,727 | | 976 | 220 | 1,196 | |
| Minority interest | 215 | – | 215 | 193 | – | 193 | | 104 | – | 104 | |
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| Profit for the yeara | 2,271 | 864 | 3,135 | 2,764 | 789 | 3,553 | | 2,609 | 455 | 3,064 | |
| Innovene operations | – | – | – | – | – | – | | – | 19 | 19 | |
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| Continuing operations | 2,271 | 864 | 3,135 | 2,764 | 789 | 3,553 | | 2,609 | 474 | 3,083 | |
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| Non-current assets | 12,433 | 9,841 | 22,274 | 11,243 | 7,612 | 18,855 | | | | | |
| Current assets | 6,073 | 2,642 | 8,715 | 5,403 | 2,184 | 7,587 | | | | | |
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| Total assets | 18,506 | 12,483 | 30,989 | 16,646 | 9,796 | 26,442 | | | | | |
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| Current liabilities | 3,547 | 1,552 | 5,099 | 3,594 | 1,272 | 4,866 | | | | | |
| Non-current liabilities | 5,562 | 3,620 | 9,182 | 4,226 | 3,370 | 7,596 | | | | | |
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| Total liabilities | 9,109 | 5,172 | 14,281 | 7,820 | 4,642 | 12,462 | | | | | |
| Minority interest | 580 | – | 580 | 473 | – | 473 | | | | | |
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| | 8,817 | 7,311 | 16,128 | 8,353 | 5,154 | 13,507 | | | | | |
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| Group investment in jointly controlled entities | | | | | | | | | | | |
| Group share of net assets (as above) | 8,817 | 7,311 | 16,128 | 8,353 | 5,154 | 13,507 | | | | | |
| Loans made by group companies to jointly controlled entities | – | 1,985 | 1,985 | – | 1,567 | 1,567 | | | | | |
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| | 8,817 | 9,296 | 18,113 | 8,353 | 6,721 | 15,074 | | | | | |
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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. |
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 2007 or at 31 December 2006.
| Sales to jointly controlled entities | | | | | | | $ million | |
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| | | | 2007 | | 2006 | | 2005 | |
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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 | 583 | 142 | 227 | 35 | – | – | |
| Atlantic LNG 2/3 Company of Trinidad and Tobago | LNG | 989 | 137 | 1,123 | 99 | 1,157 | – | |
| Pan American Energy | Crude oil | 240 | 1 | 389 | – | 75 | 2 | |
| Ruhr Oel | Employee services | 374 | 539 | 330 | 597 | 169 | 527 | |
| TNK-BP | Employee services | 150 | 69 | 189 | 99 | 125 | 14 | |
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| Purchases from jointly controlled entities | | | | | | | $ million | |
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| | | | 2007 | | 2006 | | 2005 | |
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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 | 241 | – | 254 | – | 190 | – | |
| Pan American Energy | Crude oil | 6 | 2 | 4 | 2 | 661 | 81 | |
| Ruhr Oel | Refinery operating costs | 902 | 18 | 758 | 32 | 384 | 134 | |
| TNK-BP | Crude oil and oil products | 918 | 46 | 2,662 | 85 | 908 | 17 | |
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The terms of the outstanding balances receivable from jointly controlled entities are typically 30 to 45 days, except for the receivable from Ruhr Oel, which will be paid over several years as it relates partly to pension payments. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts.
Back to Contents
27 Investments in associates
The significant associates of the group are shown in Note 46. Summarized financial information for the group’s share of associates is set out below.
| | | | | | $ million | |
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| | 2007 | | 2006 | | 2005 | |
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| Sales and other operating revenues | 9,855 | | 8,792 | | 6,879 | |
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| Profit before interest and taxation | 947 | | 669 | | 665 | |
| Finance costs and other finance expense | 57 | | 63 | | 57 | |
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| Profit before taxation | 890 | | 606 | | 608 | |
| Taxation | 193 | | 164 | | 143 | |
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| Profit for the year | 697 | | 442 | | 465 | |
| Innovene operations | – | | – | | (5 | ) |
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| Continuing operations | 697 | | 442 | | 460 | |
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| Non-current assets | 5,012 | | 6,573 | | | |
| Current assets | 2,308 | | 2,294 | | | |
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| | |
| Total assets | 7,320 | | 8,867 | | | |
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| Current liabilities | 1,801 | | 2,029 | | | |
| Non-current liabilities | 2,423 | | 2,600 | | | |
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| Total liabilities | 4,224 | | 4,629 | | | |
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| Net assets | 3,096 | | 4,238 | | | |
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| Group investment in associates | | | | | | |
| Group share of net assets (as above) | 3,096 | | 4,238 | | | |
| Loans made by group companies to associates | 1,483 | | 1,737 | | | |
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| | |
| | 4,579 | | 5,975 | | | |
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Transactions between the significant associates and the group are summarized below.
| Sales to associates | | | | | | | $ million | |
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| | | | 2007 | | 2006 | | 2005 | |
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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 | 611 | 58 | 635 | 62 | 579 | – | |
| The Baku-Tbilisi-Ceyhan Pipeline Co. | Crude oil/employee services | 86 | 2 | 112 | 4 | 99 | 3 | |
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| Purchases from associates | | | | | | | $ million | |
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| | | | 2007 | | 2006 | | 2005 | |
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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 | 547 | 303 | 866 | 91 | 1,355 | 164 | |
| Abu Dhabi Petroleum Co. | Crude oil | 1,964 | 229 | 1,547 | 145 | 2,260 | 214 | |
| The Baku-Tbilisi-Ceyhan Pipeline Co. | Transportation tariff | 394 | 42 | 155 | – | – | – | |
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The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts.
Back to Contents
28 Financial instruments and financial risk factors
The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.
| | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | 2007 | |
|
| | | | | | | | | | | | Financial | | | |
| | | | | Available-for- | | At fair value | | Derivative | liabilities | | | |
| | | Loans and | | sale financial | | through profit | | hedging | measured at | | Total carrying | |
| | Note | receivables | | assets | | and loss | | instruments | amortized cost | | amount | |
|
| Financial assets | | | | | | | | | | | | | |
| | Other investments – listed | 29 | – | | 1,617 | | – | | – | | – | | 1,617 | |
| | Other investments – unlisted | 29 | – | | 213 | | – | | – | | – | | 213 | |
| | Loans | | 1,164 | | – | | – | | – | | – | | 1,164 | |
| | Trade and other receivables | 31 | 38,710 | | – | | – | | – | | – | | 38,710 | |
| | Derivative financial instruments | 34 | – | | – | | 9,155 | | 907 | | – | | 10,062 | |
| | Cash at bank and in hand | 32 | 2,996 | | – | | – | | – | | – | | 2,996 | |
| | Cash equivalents – listed | 32 | – | | 3 | | – | | – | | – | | 3 | |
| | Cash equivalents – unlisted | 32 | – | | 563 | | – | | – | | – | | 563 | |
| Financial liabilities | | | | | | | | | | | | | |
| | Trade and other payables | 33 | – | | – | | – | | – | | (40,062 | ) | (40,062 | ) |
| | Derivative financial instruments | 34 | – | | – | | (11,284 | ) | (123 | ) | – | | (11,407 | ) |
| | Accruals | | – | | – | | – | | – | | (7,599 | ) | (7,599 | ) |
| | Finance debt | 35 | – | | – | | – | | – | | (31,045 | ) | (31,045 | ) |
|
| | | | 42,870 | | 2,396 | | (2,129 | ) | 784 | | (78,706 | ) | (34,785 | ) |
|
| | | | | | | | | | | | | | $ million | |
|
| | | | | | | | | | | | | | 2006 | |
|
| | | | | | | | | | | | Financial | | | |
| | | | | | Available-for- | | At fair value | | Derivative | | liabilities | | | |
| | | | Loans and | | sale financial | | through profit | | hedging | | measured at | | Total carrying | |
| | | Note | receivables | | assets | | and loss | | instruments | | amortized cost | | amount | |
|
| Financial assets | | | | | | | | | | | | | |
| | Other investments – listed | 29 | – | | 1,516 | | – | | – | | – | | 1,516 | |
| | Other investments – unlisted | 29 | – | | 181 | | – | | – | | – | | 181 | |
| | Loans | | 958 | | – | | – | | – | | – | | 958 | |
| | Trade and other receivables | 31 | 38,474 | | – | | – | | – | | – | | 38,474 | |
| | Derivative financial instruments | 34 | – | | – | | 12,811 | | 587 | | – | | 13,398 | |
| | Cash at bank and in hand | 32 | 2,052 | | – | | – | | – | | – | | 2,052 | |
| | Cash equivalents – listed | 32 | – | | 29 | | – | | – | | – | | 29 | |
| | Cash equivalents – unlisted | 32 | – | | 509 | | – | | – | | – | | 509 | |
| Financial liabilities | | | | | | | | | | | | | |
| | Trade and other payables | 33 | – | | – | | – | | – | | (38,227 | ) | (38,227 | ) |
| | Derivative financial instruments | 34 | – | | – | | (13,490 | ) | (137 | ) | – | | (13,627 | ) |
| | Accruals | | – | | – | | – | | – | | (7,108 | ) | (7,108 | ) |
| | Finance debt | 35 | – | | – | | – | | – | | (24,010 | ) | (24,010 | ) |
|
| | | | 41,484 | | 2,235 | | (679 | ) | 450 | | (69,345 | ) | (25,855 | ) |
|
The fair value of finance debt is shown in Note 35. For all other financial instruments, the carrying amount is either the fair value, or approximates the fair value.
Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including market risks relating to commodity prices, foreign currency exchange rates, interest rates and equity prices, credit risk and liquidity risk.
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the finance and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite.
The group’s trading activities in the oil, natural gas and power markets are managed within the integrated supply and trading function, while activities in the financial markets are managed by the treasury function. All derivative activity, whether for risk management or entrepreneurial purposes, is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control, meeting generally accepted industry practice and reflecting the principles of the Group of Thirty Global Derivatives Study recommendations.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk. A policy and risk committee monitors and validates limits and risk exposures, reviews incidents and validates risk-related policies, methodologies and procedures. A commitments committee approves value-at-risk delegations, the trading of new products, instruments and strategies and material commitments.
Back to Contents
28 Financial instruments and financial risk factors continued
(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The market price movements that the group is exposed to include oil, natural gas and power prices (commodity price risk), foreign currency exchange rates, interest rates, equity prices and other indices that could adversely affect the value of the group’s financial assets, liabilities or expected future cash flows. The group has developed policies aimed at managing the volatility inherent in certain of its natural business exposures and in accordance with these policies the group enters into various transactions using derivative financial and commodity instruments (derivatives). Derivatives are contracts whose value is derived from one or more underlying financial or commodity instruments, indices or prices that are defined in the contract. The group also trades derivatives in conjunction with its risk management activities.
The group mainly measures its market risk exposure 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 prices 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 trading 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 forwards, futures, swap agreements and options. Additionally, where physical commodities or non-derivative forward contracts 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. Market risk exposure in respect of embedded derivatives is not included in the value-at-risk table. A separate sensitivity analysis is disclosed below.
Value-at-risk limits are in place for each trading activity and for the group’s trading activity in total. The board has delegated a limit of $100 million value at risk in support of this trading activity. The high and low values at risk indicated in the table below for each type of activity are independent of each other. Through the portfolio effect the high value at risk for the group as a whole is lower than the sum of the highs for the constituent parts. The potential movement in fair values is expressed to a 95% confidence interval. This means that, in statistical terms, one would expect to see an increase or a decrease in fair values greater than the trading value at risk on one occasion per month if the portfolio were left unchanged.
| Value at risk for 1 day at 95% confidence interval | | | | | | | | $ million | |
|
| | | | | 2007 | | | | 2006 | |
|
| | High | Low | Average | Year end | High | Low | Average | Year end | |
|
| Group trading | 50 | 24 | 35 | 38 | 57 | 22 | 34 | 30 | |
| Oil price trading | 46 | 16 | 26 | 34 | 56 | 16 | 29 | 22 | |
| Natural gas price trading | 32 | 9 | 16 | 15 | 29 | 10 | 19 | 15 | |
| Power price trading | 6 | 1 | 3 | 5 | 11 | 2 | 6 | 3 | |
| Currency trading | 6 | 1 | 3 | 2 | 5 | – | 2 | – | |
| Interest rate trading | 11 | – | 5 | 2 | 1 | – | 1 | – | |
| Other trading | 7 | – | 2 | 1 | – | – | – | – | |
|
(i) Commodity price risk
The group’s risk management policy requires the management of only certain short-term exposures in respect of its equity share of oil and natural gas production and certain of its refinery and marketing activities. The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes available in the related commodity markets. Natural gas swaps, options and futures are used to mitigate price risk. Power trading is undertaken using a combination of over-the-counter forward contracts and other derivative contracts, including options and futures. This activity is on both a standalone basis and in conjunction with gas derivatives in relation to gas-generated power margin. In addition, NGLs are traded around certain US inventory locations using over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories. Trading value-at-risk information in relation to these activities is shown in the table above.
In addition, the group has embedded derivatives relating to certain natural gas and LNG contracts. Key information on these contracts is given below.
| | At 31 December 2007 | | At 31 December 2006 | |
|
| Remaining contract terms | 9 months to 11 years | | 2 to 12 years | |
| Contractual/notional amount | 3,889 million therms | | 4,968 million therms | |
| Discount rate – nominal risk free | 4.5% | | 4.5% | |
| Net fair value liability | $2,085 million | | $2,064 million | |
|
For these derivatives the sensitivity of the fair value to an immediate 10% favourable or adverse change in the key assumptions is as follows.
| | | | | | | | | | | | | | | | $ million | |
|
| | | | | | | | 2007 | | | | | | | | 2006 | |
|
| | | | Gas oil and | | | | Discount | | | | Gas oil and | | | | | |
| | Gas price | | fuel oil price | | Power price | | rate | | Gas price | | fuel oil price | | Power price | | Discount rate | |
|
| Favourable 10% change | 317 | | 72 | | 37 | | 31 | | 332 | | 7 | | 45 | | 31 | |
| Unfavourable 10% change | (368 | ) | (84 | ) | (34 | ) | (32 | ) | (341 | ) | (7 | ) | (41 | ) | (32 | ) |
|
Back to Contents
28 Financial instruments and financial risk factors continued
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. In addition, for the purposes of this analysis, 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.
(ii) Foreign currency exchange risk
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk techniques as explained above. This activity is described as currency trading in the value at risk table above.
Since BP has global operations fluctuations in foreign currency exchange rates can have significant effects on the group’s reported results. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment to movements in rates and conversion differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic currency of the group’s cash flows is the US dollar. This is because BP’s major product, oil, is priced internationally in US dollars. BP’s foreign currency exchange management policy is to minimize economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible, and then dealing with any material residual foreign currency exchange risks.
The group manages these exposures by constantly reviewing the foreign currency economic value at risk and managing such risk to keep the 12-month foreign currency value at risk below $200 million. At 31 December 2007, the foreign currency value at risk was $60 million (2006 $107 million). At no point over the past two years did the value at risk exceed the maximum risk limit. The most significant exposures relate to capital expenditure commitments and other UK and European operational requirements, for which a hedging programme is in place and hedge accounting is claimed as outlined in Note 34.
For highly probable forecast capital expenditures the group locks in the US-dollar cost of non-US dollar supplies by using currency futures. The main exposures are sterling and euro, and at 31 December 2007 open contracts were in place for $732 million sterling and $931 million euro capital expenditures, with over 80% of the deals maturing within two years (2006 $630 million sterling and $957 million euro capital expenditures with over 95% of the deals maturing within two years).
For other UK and European operational requirements the group predominantly uses cylinders to hedge the estimated exposures on a 12-month rolling basis at minimal cost. At 31 December 2007, the main open positions consisted of receive sterling, pay US dollar, purchased call and sold put options for $2,800 million; and receive euro, pay US dollar cylinders for $1,400 million.
In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2007, the total of foreign currency borrowings not swapped into US dollars amounted to $1,045 million (2006 $957 million). Of this total, $268 million (2006 $300 million) of these borrowings were denominated in currencies other than the functional currency of the individual operating unit, $191 million in Canadian dollars and $77 million in Trinidad & Tobago dollars (2006 $224 million in Canadian dollars and $76 million in Trinidad & Tobago dollars). It is estimated that a 10% change in the corresponding exchange rates would result in an exchange gain or loss in the income statement of $27 million (2006 $30 million).
(iii) Interest rate risk
Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques as described above. This activity is described as interest rate trading in the value at risk table above.
BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments, principally finance debt. While the group issues debt in a variety of currencies based on market opportunities, it uses derivatives to swap the debt to a US dollar exposure with an overall profile of one-third fixed rate to two-thirds floating rate. The proportion of floating rate debt net of interest rate swaps at 31 December 2007 was 68% of total finance debt outstanding (2006 73%). The weighted average interest rate on finance debt is 5% (2006 5%).
The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates applicable to floating rate instruments were to have increased by 1% on 1 January 2008, it is estimated that the group’s profit before taxation for 2008 would decrease by approximately $168 million (2006 $180 million). This assumes that the amount and mix of fixed and floating rate debt, including finance leases, remains unchanged from that in place at 31 December 2007 and that the change in interest rates is effective from the beginning of the year. Where the interest rate applicable to an instrument is reset during a quarter it is assumed that this occurs at the beginning of the quarter and remains unchanged for the rest of the year. In reality, the fixed/floating rate mix will fluctuate over the year and interest rates will change continually. Furthermore, the effect on earnings shown by this analysis does not consider the effect of an overall reduction in economic activity that could accompany such an increase in interest rates.
(iv) Equity price risk
The group holds equity investments that are classified as non-current available-for-sale financial assets and are measured initially at fair value with changes in fair value recognized directly in equity. On disposal, accumulated fair value changes are recycled to the income statement. Such investments are typically made for strategic purposes. At 31 December 2007, it is estimated that a change of 10% in equity prices would result in an immediate charge or credit to equity of $162 million (2006 $152 million).
At 31 December 2007, 70% of the carrying amount of non-current available-for-sale financial assets represented one equity investment, thus the group’s exposure is concentrated on changes in the share prices of this equity in particular. For further information see Note 29.
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit exposures to customers relating to outstanding receivables.
Back to Contents
28 Financial instruments and financial risk factors continued
The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy are formal delegated authorities to the sales and marketing teams to incur credit risk and to a specialized credit function to set counterparty limits; the establishment of credit systems and processes to ensure that counterparties are rated and limits set; and systems to monitor exposure against limits and report regularly on those exposures, and immediately on any excesses, and to track and report credit losses. The treasury function provides a similar credit risk management activity with respect to group-wide exposures to banks and other financial institutions.
Before trading with a new counterparty can start, its creditworthiness is assessed and a credit rating is allocated that indicates the probability of default, along with a credit exposure limit. The assessment process takes into account all available qualitative and quantitative information about the counterparty and the group, if any, to which the counterparty belongs. The counterparty’s business activities, financial resources and business risk management processes are taken into account in the assessment, to the extent that this information is publicly available or otherwise disclosed to the group by the counterparty, together with external credit ratings, if any, including ratings prepared by Moody’s Investor Service and Standard & Poor’s. Creditworthiness continues to be evaluated after transactions have been initiated and a watchlist of higher-risk counterparties is maintained. Once assigned a credit rating, each counterparty is allocated a maximum exposure limit.
The group does not aim to remove credit risk but expects to experience a certain level of credit losses. The group attempts to mitigate credit risk by entering into contracts that permit netting and allow for termination of the contract on the occurrence of certain events of default. Depending on the creditworthiness of the counterparty, the group may require collateral or other credit enhancements such as cash deposits or letters of credit and parent company guarantees. Trade and other derivative assets and liabilities are presented on a net basis where unconditional netting arrangements are in place with counterparties and where there is an intent to settle amounts due on a net basis. The maximum credit exposure associated with financial assets is equal to the carrying amount. At 31 December 2007, the maximum credit exposure was $53,498 million (2006 $55,420 million). This does not take into account collateral held of $474 million (2006 $689 million). In addition, credit exposure exists in relation to guarantees issued by group companies under which amounts outstanding at 31 December 2007 were $443 million (2006 $1,123 million) in respect of liabilities of jointly controlled entities and associates and $601 million (2006 $789 million) in respect of liabilities of other third parties.
Notwithstanding the processes described above, significant unexpected credit losses can occasionally occur. Exposure to unexpected losses increases with concentrations of credit risk that exist when a number of counterparties are involved in similar activities or operate in the same industry sector or geographical area, which may result in their ability to meet contractual obligations being impacted by changes in economic, political or other conditions. The group’s principal customers, suppliers and financial institutions with which it conducts business are located throughout the world. In addition, these risks are managed by maintaining a group watchlist and aggregating multi-segment exposures to ensure that a material credit risk is not missed.
Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by segment, and overall quality of the portfolio. The reports also include details of the largest counterparties by exposure level and expected loss, and details of counterparties on the group watchlist.
It is estimated that over 80% of the counterparties to the contracts comprising the derivative financial instruments in an asset position are of investment grade credit quality.
Trade and other receivables of the group are analysed in the table below. By comparing the BP credit ratings to the equivalent external credit ratings, it is estimated that approximately 65-70% of the trade receivables portfolio exposure are of investment grade quality. With respect to the trade and other receivables that are neither impaired nor past due, there are no indications as of the reporting date that the debtors will not meet their payment obligations.
The group does not typically renegotiate the terms of trade receivables; however, if a renegotiation does take place, the outstanding balance is included in the analysis based on the original payment terms. There were no significant renegotiated balances outstanding at 31 December 2007 or 31 December 2006.
| | | | $ million | |
|
| Trade and other receivables at 31 December | 2007 | | 2006 | |
|
| Neither impaired nor past due | 35,167 | | 34,737 | |
| Impaired (net of valuation allowance) | 145 | | 101 | |
| Not impaired and past due in the following periods | | | | |
| within 30 days | 2,350 | | 2,404 | |
| 31 to 60 days | 273 | | 475 | |
| 61 to 90 days | 311 | | 253 | |
| over 90 days | 464 | | 504 | |
|
| | 38,710 | | 38,474 | |
|
The movement in the valuation allowance for trade receivables is set out below.
| | | | $ million | |
|
| | 2007 | | 2006 | |
|
| At 1 January | 421 | | 374 | |
| Exchange adjustments | 34 | | 32 | |
| Charge for the year | 175 | | 158 | |
| Utilization | (224 | ) | (143 | ) |
|
| At 31 December | 406 | | 421 | |
|
Back to Contents
28 Financial instruments and financial risk factors continued
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, subsidiaries pool their cash surpluses to treasury, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net currency positions.
In managing its liquidity risk, the group has access to a wide range of funding at competitive rates through capital markets and banks. The group’s treasury function centrally co-ordinates relationships with banks, borrowing requirements, foreign exchange requirements and cash management. The group believes it has access to sufficient funding through the commercial paper markets and by using undrawn committed borrowing facilities to meet foreseeable borrowing requirements. At, 31 December 2007, the group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,950 million, of which $4,550 million are in place for at least four years (2006 $4,700 million of which $4,300 million are in place for at least five years). These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates.
The group has in place a European Debt Issuance Programme (DIP) under which the group may raise $15 billion of debt for maturities of one month or longer. At 31 December 2007, the amount drawn down against the DIP was $10,438 million (2006 $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 2007, the amount drawn down under the US Shelf was $2,500 million (2006 nil).
The group has long-term debt ratings of Aa1 (stable outlook) and AA+ (negative outlook), assigned respectively by Moody’s and Standard and Poor’s.
The amounts shown for finance debt in the table below include expected interest payments on borrowings and the future minimum lease payments with respect to finance leases.
There are amounts included within finance debt that we show in the table below as due within one year to reflect the earliest contractual repayment dates but that are expected to be repaid over the maximum long-term maturity profiles of the contracts as described in Note 35. US Industrial Revenue/Municipal Bonds of $2,880 million (2006 $2,744 million) with earliest contractual repayment dates within one year have expected repayment dates ranging from 1 to 35 years (2006 1 to 34 years). The bondholders typically have the option to tender these bonds for repayment on interest reset dates; however, 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 internally assessing the maturity profile of its finance debt. Similar treatment is applied for loans associated with long-term gas supply contracts totalling $1,899 million (2006 $1,976 million) that mature over 10 years.
The table also shows the timing of cash outflows relating to trade and other payables and accruals.
| | | | | | | | | | | | $ million | |
|
| | | | | | 2007 | | | | | | 2006 | |
|
| | Trade and | | | | | | Trade and | | | | | |
| | other | | | | Finance | | other | | | | Finance | |
| | payables | | Accruals | | debt | | payables | | Accruals | | debt | |
|
| Within one year | 39,576 | | 6,640 | | 16,561 | | 37,696 | | 6,147 | | 13,864 | |
| 1 to 2 years | 147 | | 351 | | 8,011 | | 100 | | 349 | | 4,146 | |
| 2 to 3 years | 62 | | 245 | | 3,515 | | 80 | | 227 | | 4,354 | |
| 3 to 4 years | 26 | | 78 | | 1,447 | | 57 | | 81 | | 723 | |
| 4 to 5 years | 30 | | 49 | | 2,352 | | 68 | | 61 | | 776 | |
| 5 to 10 years | 197 | | 200 | | 1,100 | | 226 | | 240 | | 1,778 | |
| Over 10 years | 24 | | 36 | | 1,447 | | – | | 3 | | 1,650 | |
|
| | 40,062 | | 7,599 | | 34,433 | | 38,227 | | 7,108 | | 27,291 | |
|
The group manages liquidity risk associated with derivative contracts on a portfolio basis, considering both physical commodity sale and purchase contracts together with financially-settled derivative assets and liabilities.
The held-for-trading derivatives amounts in the table below represent the total contractual cash outflows by period for the purchases of physical commodities under derivative contracts and the estimated cash outflows of financially-settled derivative liabilities. The group also holds derivative contracts for the sale of physical commodities and financially-settled derivative assets that are expected to generate cash inflows that will be available to the group to meet cash outflows on purchases and liabilities. These contracts are excluded from the table below. The amounts disclosed for embedded derivatives represent the contractual cash outflows of purchase contracts. The embedded derivatives associated with these contracts are all financial assets. There are no cash outflows associated with embedded derivatives that are financial liabilities because these are all related to sales contracts.
| | | | | | | | $ million | |
|
| | | | 2007 | | | | 2006 | |
|
| | | | Held-for- | | | | Held-for- | |
| | Embedded | | trading | | Embedded | | trading | |
| | derivatives | | derivatives | | derivatives | | derivatives | |
|
| Within one year | 699 | | 82,465 | | 707 | | 68,369 | |
| 1 to 2 years | 659 | | 8,541 | | 602 | | 8,535 | |
| 2 to 3 years | 641 | | 2,906 | | 472 | | 2,852 | |
| 3 to 4 years | 627 | | 707 | | 483 | | 913 | |
| 4 to 5 years | 624 | | 338 | | 490 | | 413 | |
| 5 to 10 years | 2,342 | | 592 | | 2,335 | | 1,626 | |
| Over 10 years | – | | 447 | | – | | 280 | |
|
| | 5,592 | | 95,996 | | 5,089 | | 82,988 | |
|
Back to Contents
28 Financial instruments and financial risk factors continued
The table below shows cash outflows for derivative hedging instruments based upon contractual payment dates. The amounts reflect the maturity profile of the fair value liability where the instruments will be settled net, and the gross settlement amount where the pay leg of a derivative will be settled separately to the receive leg, as in the case of cross-currency interest rate swaps hedging non-US dollar finance debt. The swaps are with high investment-grade counterparties and therefore the settlement day risk exposure is considered to be negligible.
| | | | $ million | |
|
| | 2007 | | 2006 | |
|
| Within one year | 1,708 | | 1,228 | |
| 1 to 2 years | 1,220 | | 1,711 | |
| 2 to 3 years | 3,759 | | 2,772 | |
| 3 to 4 years | 365 | | 117 | |
| 4 to 5 years | 1,650 | | – | |
| 5 to 10 years | 105 | | 220 | |
| Over 10 years | – | | – | |
|
| | 8,807 | | 6,048 | |
|
29 Other investments
| | | | $ million | |
|
| | 2007 | | 2006 | |
|
| Listed | 1,617 | | 1,516 | |
| Unlisted | 213 | | 181 | |
|
| | 1,830 | | 1,697 | |
|
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 most significant investment is the group’s stake in Rosneft which had a fair value of $1,285 million at 31 December 2007.
30 Inventories
| | | | $ million | |
|
| | 2007 | | 2006 | |
|
| Crude oil | 8,157 | | 5,357 | |
| Natural gas | 160 | | 127 | |
| Refined petroleum and petrochemical products | 14,723 | | 10,817 | |
|
| | 23,040 | | 16,301 | |
| Supplies | 1,517 | | 1,222 | |
|
| | 24,557 | | 17,523 | |
| Trading inventories | 1,997 | | 1,392 | |
|
| | 26,554 | | 18,915 | |
|
| Cost of inventories expensed in the income statement | 200,766 | | 187,183 | |
|
31 Trade and other receivables
| | | | | | | | $ million | |
|
|
| | | | 2007 | | | | 2006 | |
|
|
| | Current | | Non-current | | Current | | Non-current | |
|
|
| Financial assets | | | | | | | | |
| Trade receivables | 33,012 | | – | | 32,460 | | – | |
| Amounts receivable from jointly controlled entities | 888 | | – | | 830 | | – | |
| Amounts receivable from associates | 380 | | – | | 268 | | – | |
| Other receivables | 3,462 | | 968 | | 4,054 | | 862 | |
|
|
| | 37,742 | | 968 | | 37,612 | | 862 | |
|
|
| Non-financial assets | | | | | | | | |
| Other receivables | 278 | | – | | 1,080 | | – | |
|
|
| | 38,020 | | 968 | | 38,692 | | 862 | |
|
Trade and other receivables are predominantly non-interest bearing.
Back to Contents
32 Cash and cash equivalents
| | | | | $ million | |
|
|
|
|
|
|
| | | 2007 | | 2006 | |
|
|
|
|
|
|
| Cash at bank and in hand | 2,996 | | 2,052 | |
| Cash equivalents | | | | |
| | Listed | 3 | | 29 | |
| | Unlisted | 563 | | 509 | |
|
|
|
|
|
|
| | | 3,562 | | 2,590 | |
|
|
|
|
|
|
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.
Cash and cash equivalents at 31 December 2007 includes $1,294 million (2006 $773 million) that is restricted. This relates principally to amounts on deposit to cover initial margins on trading exchanges.
33 Trade and other payables
| | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
| | | | | 2007 | | | 2006 | |
|
|
|
|
|
|
|
|
|
| | | Current | | Non-current | | Current | Non-current | |
|
|
|
|
|
|
|
|
|
| Financial liabilities | | | | | | | |
| | Trade payables | 30,735 | | – | | 28,319 | – | |
| | Amounts payable to jointly controlled entities | 66 | | – | | 119 | – | |
| | Amounts payable to associates | 650 | | – | | 273 | – | |
| | Other payables | 8,125 | | 486 | | 8,985 | 531 | |
|
|
|
|
|
|
|
|
|
| | | 39,576 | | 486 | | 37,696 | 531 | |
|
|
|
|
|
|
|
|
|
| Non-financial liabilities | | | | | | | |
| | Production and similar taxes | 803 | | 765 | | 852 | 899 | |
| | Other payables | 2,773 | | – | | 3,688 | – | |
|
|
|
|
|
|
|
|
|
| | | 3,576 | | 765 | | 4,540 | 899 | |
|
|
|
|
|
|
|
|
|
| | | 43,152 | | 1,251 | | 42,236 | 1,430 | |
|
|
|
|
|
|
|
|
|
Trade and other payables are predominantly interest free.
Back to Contents
34 Derivative financial instruments
An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 28.
IAS 39 prescribes strict criteria for hedge accounting, whether as a cash flow or fair value hedge or a hedge of a net investment in a foreign operation, and requires that any derivative that does not meet these criteria should be classified as held for trading and fair valued, with gains and losses recognized in profit or loss.
In the normal course of business the group enters into 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 entrepreneurial trading operation that is undertaken in conjunction with these activities using a similar range of contracts.
The fair values of derivative financial instruments at 31 December are set out below.
| | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
| | | | | 2007 | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
| | | Fair | | Fair | | Fair | | Fair | |
| | | value | | value | | value | | value | |
| | | asset | | liability | | asset | | liability | |
|
|
|
|
|
|
|
|
|
|
| Derivatives held for trading | | | | | | | | |
| | Currency derivatives | 147 | | (317 | ) | 137 | | (32 | ) |
| | Oil price derivatives | 3,214 | | (3,432 | ) | 2,664 | | (2,368 | ) |
| | Natural gas price derivatives | 4,388 | | (4,022 | ) | 6,558 | | (5,703 | ) |
| | Power price derivatives | 1,121 | | (1,140 | ) | 3,232 | | (3,190 | ) |
| | Other derivatives | 30 | | – | | 113 | | – | |
|
|
|
|
|
|
|
|
|
|
| | | 8,900 | | (8,911 | ) | 12,704 | | (11,293 | ) |
|
|
|
|
|
|
|
|
|
|
| Embedded derivatives | | | | | | | | |
| | Natural gas and LNG contracts | 255 | | (2,340 | ) | 107 | | (2,171 | ) |
| | Interest rate contracts | – | | (33 | ) | – | | (26 | ) |
|
|
|
|
|
|
|
|
|
|
| | | 255 | | (2,373 | ) | 107 | | (2,197 | ) |
|
|
|
|
|
|
|
|
|
|
| Cash flow hedges | 348 | | (97 | ) | 219 | | (33 | ) |
|
|
|
|
|
|
|
|
|
|
| Fair value hedges | | | | | | | | |
| | Currency forwards, futures and swaps | 430 | | (9 | ) | 228 | | (13 | ) |
| | Interest rate swaps | 89 | | (17 | ) | 33 | | (91 | ) |
|
|
|
|
|
|
|
|
|
|
| | | 519 | | (26 | ) | 261 | | (104 | ) |
|
|
|
|
|
|
|
|
|
|
| Hedges of net investments in foreign operations | 40 | | – | | 107 | | – | |
|
|
|
|
|
|
|
|
|
|
| | | 10,062 | | (11,407 | ) | 13,398 | | (13,627 | ) |
|
|
|
|
|
|
|
|
|
|
| Of which – current | 6,321 | | (6,405 | ) | 10,373 | | (9,424 | ) |
| | – non-current | 3,741 | | (5,002 | ) | 3,025 | | (4,203 | ) |
|
|
|
|
|
|
|
|
|
|
Back to Contents
34 Derivative financial instruments continued
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at fair value with 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 as described in Note 28.
The following tables show further information on 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 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | Oil | | Natural gas | | Power | | | |
| | Currency | | price | | price | | price | | Other | |
|
|
|
|
|
|
|
|
|
|
|
| Fair value of contracts at 1 January 2007 | 105 | | 296 | | 855 | | 42 | | 113 | |
| Contracts realized or settled in the year | (109 | ) | (289 | ) | (602 | ) | (68 | ) | (83 | ) |
| Fair value of options at inception | – | | 28 | | 168 | | 36 | | – | |
| Fair value of other new contracts entered into during the year | – | | – | | 1 | | – | | – | |
| Changes in fair values relating to price | (167 | ) | (253 | ) | (58 | ) | (20 | ) | – | |
| Exchange adjustments | 1 | | – | | 2 | | (9 | ) | – | |
|
|
|
|
|
|
|
|
|
|
|
| Fair value of contracts at 31 December 2007 | (170 | ) | (218 | ) | 366 | | (19 | ) | 30 | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | Oil | | Natural gas | | Power | | | |
| | Currency | | price | | price | | price | | Other | |
|
|
|
|
|
|
|
|
|
|
|
| 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 | | – | | – | | – | |
| Changes in fair values relating to price | 98 | | 231 | | 421 | | (22 | ) | 174 | |
| Exchange adjustments | – | | 4 | | (17 | ) | (13 | ) | – | |
|
|
|
|
|
|
|
|
|
|
|
| Fair value of contracts at 31 December 2006 | 105 | | 296 | | 855 | | 42 | | 113 | |
|
|
|
|
|
|
|
|
|
|
|
If at inception of a contract the valuation cannot be supported by observable market data, any gain determined by the valuation methodology is not recognized in the income statement but is deferred on the balance sheet and is commonly known as ‘day-one profit’. This deferred gain is recognized in the income statement over the life of the contract until substantially all of the remaining contract term can be valued using observable market data at which point any remaining deferred gain is recognized in income. Changes in valuation from this initial valuation are recognized immediately through income.
Back to Contents
34 Derivative financial instruments continued
The following table shows the changes in the day-one profits deferred on the balance sheet.
| | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
| | | | 2007 | | | | 2006 | |
|
|
|
|
|
|
|
|
|
| | Natural | | | | Natural | | | |
| | gas price | | Power price | | gas price | | Power price | |
|
|
|
|
|
|
|
|
|
| Fair value of contracts not recognized through the income statement at 1 January | 36 | | – | | 39 | | 10 | |
| Fair value of new contracts at inception not recognized in the income statement | 1 | | – | | 2 | | 1 | |
| Fair value recognized in the income statement | (1 | ) | – | | (5 | ) | (11 | ) |
|
|
|
|
|
|
|
|
|
| Fair value of contracts not recognized through profit at 31 December | 36 | | – | | 36 | | – | |
|
|
|
|
|
|
|
|
|
Derivative assets held for trading have the following fair values and maturities.
| | | | | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | | | 2007 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Currency derivatives | 123 | | 10 | | 6 | | 5 | | 1 | | 2 | | 147 | |
| Oil price derivatives | 2,545 | | 471 | | 113 | | 39 | | 26 | | 20 | | 3,214 | |
| Natural gas price derivatives | 2,170 | | 677 | | 333 | | 283 | | 216 | | 709 | | 4,388 | |
| Power price derivatives | 819 | | 250 | | 52 | | – | | – | | – | | 1,121 | |
| Other derivatives | 12 | | 18 | | – | | – | | – | | – | | 30 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | 5,669 | | 1,426 | | 504 | | 327 | | 243 | | 731 | | 8,900 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Currency derivatives | 117 | | – | | 12 | | 3 | | 2 | | 3 | | 137 | |
| Oil price derivatives | 2,520 | | 116 | | 20 | | 7 | | 1 | | – | | 2,664 | |
| Natural gas price derivatives | 4,532 | | 919 | | 374 | | 166 | | 114 | | 453 | | 6,558 | |
| Power price derivatives | 2,845 | | 274 | | 86 | | 27 | | – | | – | | 3,232 | |
| Other derivatives | 64 | | 26 | | 23 | | – | | – | | – | | 113 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | 10,078 | | 1,335 | | 515 | | 203 | | 117 | | 456 | | 12,704 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities held for trading have the following fair values and maturities.
| | | | | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | | | 2007 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Currency derivatives | (145 | ) | (99 | ) | (32 | ) | (16 | ) | (15 | ) | (10 | ) | (317 | ) |
| Oil price derivatives | (2,735 | ) | (512 | ) | (135 | ) | (25 | ) | (22 | ) | (3 | ) | (3,432 | ) |
| Natural gas price derivatives | (2,089 | ) | (527 | ) | (298 | ) | (219 | ) | (185 | ) | (704 | ) | (4,022 | ) |
| Power price derivatives | (832 | ) | (246 | ) | (61 | ) | (1 | ) | – | | – | | (1,140 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | (5,801 | ) | (1,384 | ) | (526 | ) | (261 | ) | (222 | ) | (717 | ) | (8,911 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | | | 2006 | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Less than | | | | | | | | | | Over | | | |
| | 1 year | | 1-2 years | | 2-3 years | | 3-4 years | | 4-5 years | | 5 years | | Total | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Currency derivatives | (8 | ) | (7 | ) | (12 | ) | (2 | ) | (2 | ) | (1 | ) | (32 | ) |
| Oil price derivatives | (2,230 | ) | (89 | ) | (29 | ) | (19 | ) | (1 | ) | – | | (2,368 | ) |
| Natural gas price derivatives | (3,931 | ) | (875 | ) | (273 | ) | (109 | ) | (86 | ) | (429 | ) | (5,703 | ) |
| Power price derivatives | (2,777 | ) | (289 | ) | (98 | ) | (26 | ) | – | | – | | (3,190 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | (8,946 | ) | (1,260 | ) | (412 | ) | (156 | ) | (89 | ) | (430 | ) | (11,293 | ) |
|
|
|
|
|
|
|
|
|
|
|
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Back to Contents
34 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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| | 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 | 119 | | 3 | | 49 | | 2 | | (9 | ) | 1 | | 165 | |
| Prices sourced from observable data or market corroboration | (212 | ) | 58 | | (57 | ) | 82 | | 37 | | – | | (92 | ) |
| Prices based on models and other valuation methods | (39 | ) | (19 | ) | (14 | ) | (18 | ) | (7 | ) | 13 | | (84 | ) |
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| | (132 | ) | 42 | | (22 | ) | 66 | | 21 | | 14 | | (11 | ) |
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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 | 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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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 $94 million (2006 $117 million loss and 2005 $130 million gain).
Gains and losses relating to derivative contracts are included either within sales and other operating revenues or within purchases in the income statement depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures, options, swaps and certain forward sales and forward purchases contracts. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be fair valued under accounting standards. Also included within sales and other operating revenues are gains and losses on inventory held for trading purposes. The total amount relating to all of these items was a gain of $376 million (2006 $2,842 million gain and 2005 $838 million gain).
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 models with inputs that include price curves for each of the different products that are built up from active market pricing data and extrapolated to the expiry of the contracts in 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. Price volatility data is also an input for the models.
Back to Contents
34 Derivative financial instruments continued
The following table shows the changes during the year in the net fair value of embedded derivatives.
| | | | | | | | $ million | |
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| | | | 2007 | | | | 2006 | |
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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 | (2,064 | ) | (26 | ) | (2,511 | ) | (30 | ) |
| Contracts realized or settled in the year | 449 | | – | | 762 | | – | |
| Changes in valuation techniques or key assumptions | 130 | | – | | – | | – | |
| Changes in fair values relating to price | (567 | ) | (7 | ) | 21 | | 4 | |
| Exchange adjustments | (33 | ) | – | | (336 | ) | – | |
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| Fair value of contracts at 31 December | (2,085 | ) | (33 | ) | (2,064 | ) | (26 | ) |
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Embedded derivative assets have the following fair 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 | 193 | | 18 | | 15 | | 7 | | 10 | | 12 | | 255 | |
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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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| Natural gas and LNG embedded derivatives | 49 | | 58 | | – | | – | | – | | – | | 107 | |
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Embedded derivative liabilities have the following fair 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 | (554 | ) | (437 | ) | (299 | ) | (244 | ) | (219 | ) | (587 | ) | (2,340 | ) |
| Interest rate embedded derivatives | (33 | ) | – | | – | | – | | – | | – | | (33 | ) |
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| | (587 | ) | (437 | ) | (299 | ) | (244 | ) | (219 | ) | (587 | ) | (2,373 | ) |
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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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| Natural gas and LNG embedded derivatives | (444 | ) | (433 | ) | (320 | ) | (218 | ) | (186 | ) | (570 | ) | (2,171 | ) |
| Interest rate embedded derivatives | – | | (26 | ) | – | | – | | – | | – | | (26 | ) |
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| | (444 | ) | (459 | ) | (320 | ) | (218 | ) | (186 | ) | (570 | ) | (2,197 | ) |
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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 | 61 | | – | | – | | – | | – | | – | | 61 | |
| Prices based on models and other valuation methods | (455 | ) | (419 | ) | (284 | ) | (237 | ) | (209 | ) | (575 | ) | (2,179 | ) |
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| | (394 | ) | (419 | ) | (284 | ) | (237 | ) | (209 | ) | (575 | ) | (2,118 | ) |
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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 | 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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The net change in fair value of contracts based on models and other valuation methods during the year is a gain of $18 million (2006 gain of $423 million and 2005 loss of $1,773 million).
Back to Contents
34 Derivative financial instruments continued
The fair value gain (loss) on embedded derivatives is shown below.
| | | | | | | $ million | |
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| | | 2007 | | 2006 | | 2005 | |
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| Natural gas and LNG embedded derivatives | | – | | 604 | | (2,034 | ) |
| Interest rate embedded derivatives | | (7 | ) | 4 | | (13 | ) |
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| Fair value gain (loss) | | (7 | ) | 608 | | (2,047 | ) |
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The fair value gain (loss) in the above table includes $12 million of exchange losses (2006 $179 million of exchange losses and 2005 $115 million of exchange gains) arising on contracts that are denominated in a currency other than the functional currency of the individual operating unit.
Cash flow hedges
At 31 December 2007, the group held futures currency contracts and cylinders that were being used to hedge the foreign currency risk of highly probable forecast transactions, as well as cross-currency interest rate swaps to fix the US dollar interest rate and US dollar redemption value, with matching critical terms on the currency leg of the swap with the underlying non-US dollar debt issuance. Note 28 outlines the management of risk aspects for currency and interest rate risk. For cash flow hedges the group only claims for the intrinsic value on the currency with any fair value attributable to time value taken immediately to profit or loss. There were no highly probable transactions for which hedge accounting has been claimed that have not occurred and no significant element of hedge ineffectiveness requiring recognition in the income statement. For cash flow hedges the pre-tax amount removed from equity during the period and included in the income statement is a gain of $74 million (2006 $93 million and 2005 $36 million loss). Of this, a gain of $143 million is included in production and manufacturing expenses (2006 $162 million gain and 2005 $33 million gain) and a loss of $69 million is included in finance costs (2006 $69 million loss and 2005 $69 million loss). The amount removed from equity during the period and included in the carrying amount of non-financial assets was a gain of $40 million (2006 $6 million gain and nil for 2005).
The amounts retained in equity at 31 December 2007 are expected to mature and affect the income statement by a $48 million gain in 2008, a loss of $10 million in 2009 and a gain of $28 million in 2010 and beyond.
Fair value hedges
At 31 December 2007, 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. The receive leg of the swap contracts is largely identical for all critical aspects to the terms of the underlying debt and thus the hedging is highly effective. The gain on the hedging derivative instruments taken to the income statement in 2007 was $334 million (2006 $257 million) offset by a loss on the fair value of the finance debt of $327 million (2006 $257 million loss).
The interest rate and currency swaps have an average maturity of one to two years, (2006 two to three years) and are used to convert sterling, euro, Swiss franc and Australian dollar denominated borrowings into US dollar floating rate debt. Note 28 outlines the group’s approach to interest rate risk management.
Hedges of net investments in foreign operations
The group holds currency swap contracts as a hedge of a long-term investment in a UK subsidiary expiring in 2009. At 31 December 2007, the hedge had a fair value of $40 million (2006 $107 million) and the loss on the hedge recognized in equity in 2007 was $67 million (2006 $105 million gain, 2005 $58 million gain). US dollars have been sold forward for sterling purchased and match the underlying liability with no significant ineffectiveness reflected in the income statement.
35 Finance debt
| | | | | | | | | | | | | $ million | |
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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 | | 542 | | 978 | | 1,520 | | 543 | | 806 | | 1,349 | |
| Other loans | | 14,607 | | 14,026 | | 28,633 | | 12,321 | | 9,525 | | 21,846 | |
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| Total borrowings | | 15,149 | | 15,004 | | 30,153 | | 12,864 | | 10,331 | | 23,195 | |
| Net obligations under finance leases | | 245 | | 647 | | 892 | | 60 | | 755 | | 815 | |
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| | | 15,394 | | 15,651 | | 31,045 | | 12,924 | | 11,086 | | 24,010 | |
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| | | | | | | | | | | | | | |
| a | Amounts due within one year include current maturities of long-term debt and borrowings that are expected to be repaid later than the earliest contractual repayment dates of within one year. US Industrial Revenue/Municipal Bonds of $2,880 million (2006 $2,744 million) with earliest contractual repayment dates within one year have expected repayment dates ranging from 1 to 35 years (2006 1 to 34 years). The bondholders typically have the option to tender these bonds for repayment on interest reset dates; however, 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 internally assessing the maturity profile of its finance debt. Similar treatment is applied for loans associated with long-term gas supply contracts totalling $1,899 million (2006 $1,976 million) that mature over 10 years. |
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Back to Contents
35 Finance debt continued
The following table shows, by major currency, the group’s finance debt at 31 December 2007 and 2006 and the weighted average interest rates achieved at those dates through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures.
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| | | | | Fixed rate debt | | Floating rate debt | | | |
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| | | | | Weighted | | | | | | | | | |
| | | Weighted | | average | | | | Weighted | | | | | |
| | | average | | time for | | | | average | | | | | |
| | | interest | | which rate | | | | interest | | | | | |
| | | rate | | is fixed | | Amount | | rate | | Amount | | Total | |
| | | % | | Years | | $ million | | % | | $ million | | $ million | |
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| US dollar | | 5 | | 2 | | 9,541 | | 5 | | 20,460 | | 30,001 | |
| Sterling | | – | | – | | – | | 6 | | 35 | | 35 | |
| Euro | | 4 | | 4 | | 81 | | 5 | | 107 | | 188 | |
| Other currencies | | 7 | | 13 | | 268 | | 7 | | 553 | | 821 | |
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| | | | | | | 9,890 | | | | 21,155 | | 31,045 | |
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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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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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| | | | 2007 | | 2006 | |
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| Future minimum lease payments payable within | | | | | |
| 1 year | | 268 | | 82 | |
| 2 to 5 years | | 393 | | 376 | |
| Thereafter | | 630 | | 873 | |
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| | | | 1,291 | | 1,331 | |
| Less finance charges | | 399 | | 516 | |
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| Net obligations | | 892 | | 815 | |
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| Of which | – payable within 1 year | | 245 | | 60 | |
| | – payable within 2 to 5 years | | 217 | | 164 | |
| | – payable thereafter | | 430 | | 591 | |
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Back to Contents
35 Finance debt continued
Fair values
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 2007, whereas in the balance sheet the amount would be reported as current liabilities.
The carrying amount of the group’s short-term borrowings, comprising mainly commercial paper, bank loans, overdrafts and US Industrial Revenue/ Municipal Bonds, 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.
| | | | | | | | | $ million | |
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| | | | | 2007 | | | | 2006 | |
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| | | | | Carrying | | | | Carrying | |
| | | Fair value | | amount | | Fair value | | amount | |
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| Short-term borrowings | | 11,212 | | 11,212 | | 9,661 | | 9,661 | |
| Long-term borrowings | | 19,094 | | 18,941 | | 13,580 | | 13,534 | |
| Net obligations under finance leases | | 908 | | 892 | | 832 | | 815 | |
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| Total finance debt | | 31,214 | | 31,045 | | 24,073 | | 24,010 | |
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36 Capital disclosures and analysis of changes in net debt
The group defines capital as the total equity of the group. The group’s objective for managing capital is to deliver competitive, secure and sustainable returns to maximize long-term shareholder value. BP is not subject to any externally-imposed capital requirements.
The group’s approach to managing capital is set out in its financial framework. The group aims to maintain capital discipline in relation to investing activities while progressively growing the dividend per share. A managed share buyback programme is used to return to shareholders all sustainable free cash flow in excess of the group’s investment and dividend needs. From 2008, the group intends to rebalance returns to shareholders by increasing the dividend component. As a result, the level of free cash flow allocated to share buybacks is likely to be lower; however, we will continue to use share buybacks as a mechanism to return excess cash to shareholders when appropriate.
The group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross finance debt, as shown in the balance sheet, less cash and cash equivalents. All components of equity are included in the denominator of the calculation. We believe that a net debt ratio in the range 20-30% provides an efficient capital structure and an appropriate level of financial flexibility.
At 31 December 2007 the net debt ratio was 23% (2006 20%).
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| | | 2007 | | 2006 | |
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| Gross debt | | 31,045 | | 24,010 | |
| Cash and cash equivalents | | 3,562 | | 2,590 | |
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| Net debt | | 27,483 | | 21,420 | |
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| Equity | | 94,652 | | 85,465 | |
| Net debt ratio | | 23 | % | 20 | % |
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An analysis of changes in net debt is provided below.
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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 | | (24,010 | ) | 2,590 | | (21,420 | ) | (19,162 | ) | 2,960 | | (16,202 | ) |
| Exchange adjustments | | (122 | ) | 135 | | 13 | | (172 | ) | 47 | | (125 | ) |
| Debt acquired | | – | | – | | – | | (13 | ) | – | | (13 | ) |
| Net cash flow | | (6,411 | ) | 837 | | (5,574 | ) | (4,049 | ) | (417 | ) | (4,466 | ) |
| Fair value hedge adjustment | | (368 | ) | – | | (368 | ) | (581 | ) | – | | (581 | ) |
| Other movements | | (134 | ) | – | | (134 | ) | (33 | ) | – | | (33 | ) |
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| At 31 December | | (31,045 | ) | 3,562 | | (27,483 | ) | (24,010 | ) | 2,590 | | (21,420 | ) |
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| Equity | | | | | | 94,652 | | | | | | 85,465 | |
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Back to Contents
37 Provisions
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| | | | | | | Litigation | | | |
| | | Decommissioning | | Environmental | | and other | | Total | |
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| At 1 January 2007 | 8,365 | | 2,127 | | 3,152 | | 13,644 | |
| Exchange adjustments | 168 | | 19 | | 11 | | 198 | |
| New or increased provisions | 1,163 | | 373 | | 1,376 | | 2,912 | |
| Write-back of unused provisions | – | | (151 | ) | (196 | ) | (347 | ) |
| Unwinding of discount | 195 | | 44 | | 44 | | 283 | |
| Utilization | (297 | ) | (305 | ) | (899 | ) | (1,501 | ) |
| Deletions | (93 | ) | – | | (1 | ) | (94 | ) |
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| At 31 December 2007 | 9,501 | | 2,107 | | 3,487 | | 15,095 | |
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| Of which | – expected to be incurred within 1 year | 447 | | 431 | | 1,317 | | 2,195 | |
| | – expected to be incurred in more than 1 year | 9,054 | | 1,676 | | 2,170 | | 12,900 | |
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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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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% (2006 2.0%) . These costs are generally 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 is reliably 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% (2006 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 the liability.
Included within the litigation and other category at 31 December 2007 are provisions for litigation of $1,737 million (2006 $1,474 million) for deferred employee compensation of $761 million (2006 $760 million) and provisions for expected rental shortfalls on surplus properties of $320 million (2006 $320 million). New or increased provisions made for 2007 included an amount of $500 million (2006 $425 million) in respect of the Texas City incident, of which, disbursements to claimants in 2007 were $314 million (2006 $863 million) and the provision at 31 December 2007 was $456 million (2006 $270 million).
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% (2006 4.5%) or a real discount rate of 2.0% (2006 2.0%), as appropriate.
Back to Contents
38 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, the primary pension arrangement in the UK is a funded final salary pension plan that 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.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. During 2007, contributions of $524 million (2006 $438 million and 2005 $340 million) and $97 million (2006 $181 million and 2005 $279 million) were made to the UK plans and US plans respectively. In addition, contributions of $127 million (2006 $136 million and 2005 $140 million) were made to other funded defined benefit plans. The aggregate level of contributions in 2008 is expected to be approximately $500 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 obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date of the most recent actuarial review was 31 December 2007.
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 2007 are used to determine the pension liabilities at that date and the pension cost for 2008.
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| Financial assumptions | UK | | US | | Other | |
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| | 2007 | | 2006 | | 2005 | | 2007 | | 2006 | | 2005 | | 2007 | | 2006 | | 2005 | |
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| Discount rate for pension plan liabilities | 5.7 | | 5.1 | | 4.75 | | 6.1 | | 5.7 | | 5.50 | | 5.6 | | 4.8 | | 4.00 | |
| Discount rate for post-retirement benefit plans | n/a | | n/a | | n/a | | 6.4 | | 5.9 | | 5.50 | | n/a | | n/a | | n/a | |
| Rate of increase in salariesa | 5.1 | | 4.7 | | 4.25 | | 4.2 | | 4.2 | | 4.25 | | 3.7 | | 3.6 | | 3.25 | |
| Rate of increase for pensions in payment | 3.2 | | 2.8 | | 2.50 | | – | | – | | – | | 1.8 | | 1.8 | | 1.75 | |
| Rate of increase in deferred pensions | 3.2 | | 2.8 | | 2.50 | | – | | – | | – | | 1.2 | | 1.1 | | 1.00 | |
| Inflation | 3.2 | | 2.8 | | 2.50 | | 2.4 | | 2.4 | | 2.50 | | 2.2 | | 2.2 | | 2.00 | |
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| a | This assumption includes an allowance for promotion-related salary growth, of between 0.3% and 0.4% depending on country. |
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 | | US | | Germany | |
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| | 2007 | | 2006 | | 2005 | | 2007 | | 2006 | | 2005 | | 2007 | | 2006 | | 2005 | |
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| Life expectancy at age 60 for a male currently aged 60 | 24.0 | | 23.9 | | 23.0 | | 24.3 | | 24.2 | | 21.9 | | 22.4 | | 22.2 | | 22.1 | |
| Life expectancy at age 60 for a female currently aged 60 | 26.9 | | 26.8 | | 26.0 | | 26.1 | | 26.0 | | 25.6 | | 27.0 | | 26.9 | | 26.7 | |
| Life expectancy at age 60 for a male currently aged 40 | 25.1 | | 25.0 | | 23.9 | | 25.8 | | 25.8 | | 21.9 | | 25.3 | | 25.2 | | 25.0 | |
| Life expectancy at age 60 for a female currently aged 40 | 27.9 | | 27.8 | | 26.9 | | 27.0 | | 26.9 | | 25.6 | | 29.7 | | 29.6 | | 29.4 | |
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The assumed future US healthcare cost trend rate is as follows:
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| Initial US healthcare cost trend rate | 9.0 | | 9.3 | | 10.3 | |
| Ultimate US healthcare cost trend rate | 5.0 | | 5.0 | | 5.0 | |
| Year in which ultimate trend rate is reached | 2013 | | 2013 | | 2013 | |
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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.
Back to Contents
38 Pensions and other post-retirement benefits continued
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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| 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 as part of their asset mix and to manage 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.
The expected long-term rates of return and market values of the various categories of asset held by the defined benefit plans at 31 December are set out below. The market values shown include the effects of derivative financial instruments.
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| | Expected | | | | Expected | | | | Expected | | | |
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| | 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 | 8.0 | | 24,106 | | 7.5 | | 23,631 | | 7.50 | | 18,465 | |
| Bonds | 4.4 | | 5,279 | | 4.7 | | 3,881 | | 4.25 | | 2,719 | |
| Property | 6.5 | | 1,259 | | 6.5 | | 1,370 | | 6.50 | | 1,097 | |
| Cash | 5.6 | | 977 | | 3.8 | | 379 | | 3.50 | | 1,001 | |
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| | 7.3 | | 31,621 | | 7.0 | | 29,261 | | 7.00 | | 23,282 | |
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| US pension plans | | | | | | | | | | | | |
| Equities | 8.5 | | 6,610 | | 8.5 | | 6,528 | | 8.50 | | 5,961 | |
| Bonds | 5.0 | | 1,347 | | 5.0 | | 1,371 | | 4.75 | | 1,079 | |
| Property | 8.0 | | 16 | | 8.0 | | 15 | | 8.00 | | 21 | |
| Cash | 3.6 | | 72 | | 3.2 | | 41 | | 3.00 | | 256 | |
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| | 8.0 | | 8,045 | | 8.0 | | 7,955 | | 8.00 | | 7,317 | |
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| US other post-retirement benefit plans | | | | | | | | | | | | |
| Equities | 8.5 | | 17 | | 8.5 | | 19 | | 8.50 | | 20 | |
| Bonds | 5.0 | | 6 | | 5.0 | | 7 | | 4.75 | | 8 | |
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| | 7.6 | | 23 | | 7.5 | | 26 | | 7.25 | | 28 | |
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| Other plans | | | | | | | | | | | | |
| Equities | 8.1 | | 1,260 | | 7.6 | | 1,158 | | 7.50 | | 991 | |
| Bonds | 5.0 | | 1,491 | | 4.6 | | 1,199 | | 4.00 | | 943 | |
| Property | 5.7 | | 145 | | 4.7 | | 120 | | 5.75 | | 130 | |
| Cash | 4.2 | | 214 | | 3.0 | | 191 | | 1.50 | | 216 | |
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| | 6.4 | | 3,110 | | 5.8 | | 2,668 | | 5.50 | | 2,280 | |
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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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| Investment return | | | | |
| Effect on pension and other post-retirement benefit expense in 2008 | (419 | ) | 415 | |
| Discount rate | | | | |
| Effect on pension and other post-retirement benefit expense in 2008 | (84 | ) | 114 | |
| Effect on pension and other post-retirement benefit obligation at 31 December 2007 | (5,039 | ) | 6,459 | |
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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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| | Increase | | Decrease | |
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| Effect on US other post-retirement benefit expense in 2008 | 32 | | (26 | ) |
| Effect on US other post-retirement obligation at 31 December 2007 | 358 | | (295 | ) |
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Back to Contents
38 Pensions and other post-retirement benefits continued
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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 costa | 492 | | 227 | | 43 | | 132 | | 894 | |
| Past service cost | 5 | | 10 | | – | | – | | 15 | |
| Settlement, curtailment and special termination benefits | 36 | | – | | – | | 2 | | 38 | |
| Payments to defined contribution plans | – | | 184 | | – | | 25 | | 209 | |
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| Total operating chargeb | 533 | | 421 | | 43 | | 159 | | 1,156 | |
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| Analysis of the amount credited (charged) to other finance expense | | | | | | | | | | |
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| Expected return on plan assets | 2,075 | | 613 | | 2 | | 165 | | 2,855 | |
| Interest on plan liabilities | (1,198 | ) | (425 | ) | (190 | ) | (390 | ) | (2,203 | ) |
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| Other finance income (expense) | 877 | | 188 | | (188 | ) | (225 | ) | 652 | |
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| Analysis of the amount recognized in the statement of recognized income and expense | | | | | | | | | | |
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| Actual return less expected return on pension plan assets | 406 | | (28 | ) | – | | (76 | ) | 302 | |
| Change in assumptions underlying the present value of the plan liabilities | 513 | | 358 | | 137 | | 607 | | 1,615 | |
| Experience gains and losses arising on the plan liabilities | (162 | ) | (27 | ) | 29 | | (40 | ) | (200 | ) |
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| Actuarial gain recognized in statement of recognized income and expense | 757 | | 303 | | 166 | | 491 | | 1,717 | |
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| Movements in benefit obligation during the year | | | | | | | | | | |
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| Benefit obligation at 1 January | 23,289 | | 7,695 | | 3,300 | | 8,149 | | 42,433 | |
| Exchange adjustments | 394 | | – | | – | | 917 | | 1,311 | |
| Current service costa | 492 | | 227 | | 43 | | 132 | | 894 | |
| Past service cost | 5 | | 10 | | – | | – | | 15 | |
| Interest cost | 1,198 | | 425 | | 190 | | 390 | | 2,203 | |
| Curtailment | (7 | ) | – | | – | | – | | (7 | ) |
| Settlement | (3 | ) | – | | – | | – | | (3 | ) |
| Special termination benefitsc | 46 | | – | | – | | 2 | | 48 | |
| Contributions by plan participants | 43 | | – | | – | | 12 | | 55 | |
| Benefit payments (funded plans)d | (1,085 | ) | (580 | ) | (5 | ) | (182 | ) | (1,852 | ) |
| Benefit payments (unfunded plans)d | (3 | ) | (37 | ) | (184 | ) | (379 | ) | (603 | ) |
| Acquisitions | – | | – | | – | | 141 | | 141 | |
| Disposals | (91 | ) | – | | – | | (29 | ) | (120 | ) |
| Actuarial gain on obligation | (351 | ) | (331 | ) | (166 | ) | (567 | ) | (1,415 | ) |
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| Benefit obligation at 31 Decembera | 23,927 | | 7,409 | | 3,178 | | 8,586 | | 43,100 | |
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| Movements in fair value of plan assets during the year | | | | | | | | | | |
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| Fair value of plan assets at 1 January | 29,261 | | 7,955 | | 26 | | 2,668 | | 39,910 | |
| Exchange adjustments | 488 | | – | | – | | 316 | | 804 | |
| Expected return on plan assetsa, e | 2,075 | | 613 | | 2 | | 165 | | 2,855 | |
| Contributions by plan participants | 43 | | – | | – | | 12 | | 55 | |
| Contributions by employers (funded plans) | 524 | | 97 | | – | | 127 | | 748 | |
| Benefit payments (funded plans)d | (1,085 | ) | (580 | ) | (5 | ) | (182 | ) | (1,852 | ) |
| Acquisitions | – | | – | | – | | 101 | | 101 | |
| Disposals | (91 | ) | (12 | ) | – | | (21 | ) | (124 | ) |
| Actuarial gain on plan assetse | 406 | | (28 | ) | – | | (76 | ) | 302 | |
|
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|
|
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|
|
|
| Fair value of plan assets at 31 December | 31,621 | | 8,045 | | 23 | | 3,110 | | 42,799 | |
|
| Surplus (deficit) at 31 December | 7,694 | | 636 | | (3,155 | ) | (5,476 | ) | (301 | ) |
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|
|
|
| Represented by | | | | | | | | | | |
| Asset recognized | 7,818 | | 989 | | – | | 107 | | 8,914 | |
| Liability recognized | (124 | ) | (353 | ) | (3,155 | ) | (5,583 | ) | (9,215 | ) |
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| | 7,694 | | 636 | | (3,155 | ) | (5,476 | ) | (301 | ) |
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|
| The surplus (deficit) may be analysed between funded and unfunded plans as follows | | | | | | | | | | |
| Funded | 7,818 | | 978 | | (29 | ) | (263 | ) | 8,504 | |
| Unfunded | (124 | ) | (342 | ) | (3,126 | ) | (5,213 | ) | (8,805 | ) |
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| | 7,694 | | 636 | | (3,155 | ) | (5,476 | ) | (301 | ) |
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| The defined benefit obligation may be analysed between funded and unfunded plans as follows | | | | | | | | | | |
| Funded | (23,803 | ) | (7,067 | ) | (52 | ) | (3,373 | ) | (34,295 | ) |
| Unfunded | (124 | ) | (342 | ) | (3,126 | ) | (5,213 | ) | (8,805 | ) |
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| | (23,927 | ) | (7,409 | ) | (3,178 | ) | (8,586 | ) | (43,100 | ) |
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| a | The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions fund benefits are generally included in current service cost and the costs of administering our other post-retirement benefits are included in the benefit obligation. |
| b | Included within production and manufacturing expenses and distribution and administration expenses. |
| c | The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of a restructuring programme in the UK. |
| d | The benefit payments amount shown above comprises $2,398 million benefits plus $57 million of fund expenses incurred in the administration of the benefit. |
| e | 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 2007 reimbursement balances due from or to other companies in respect of pensions amounted to $496 million reimbursement assets (2006 $479 million) and $72 million reimbursement liabilities (2006 $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
38 Pensions and other post-retirement benefits continued
| | | | | | | | | | $ million | |
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| | | | | | | | | | 2006 | |
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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 costa | 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 | |
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| Total operating chargeb | 362 | | 415 | | 42 | | 421 | | 1,240 | |
|
| Analysis of the amount credited (charged) to other finance expense | | | | | | | | | | |
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| Expected return on plan assets | 1,711 | | 564 | | 2 | | 133 | | 2,410 | |
| Interest on plan liabilities | (1,006 | ) | (423 | ) | (186 | ) | (325 | ) | (1,940 | ) |
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| Other finance income (expense) | 705 | | 141 | | (184 | ) | (192 | ) | 470 | |
|
| Analysis of the amount recognized in the statement of recognized income and expense | | | | | | | | | | |
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| 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 | ) |
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|
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| Actuarial gain recognized in statement of recognized income and expense | 1,395 | | 733 | | 191 | | 296 | | 2,615 | |
|
| Movements in benefit obligation during the year | | | | | | | | | | |
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|
|
| 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 benefitsc | 46 | | – | | – | | 227 | | 273 | |
| Contributions by plan participants | 38 | | – | | – | | 5 | | 43 | |
| Benefit payments (funded plans)d | (981 | ) | (615 | ) | (4 | ) | (149 | ) | (1,749 | ) |
| Benefit payments (unfunded plans)d | – | | (37 | ) | (211 | ) | (321 | ) | (569 | ) |
| Acquisitions | – | | – | | – | | – | | – | |
| Disposals | 143 | | (18 | ) | – | | (7 | ) | 118 | |
| Actuarial gain on obligation | (90 | ) | (212 | ) | (191 | ) | (155 | ) | (648 | ) |
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|
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| 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 | | | | | | | | | | |
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|
|
| 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 assetsa, e | 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)d | (981 | ) | (615 | ) | (4 | ) | (149 | ) | (1,749 | ) |
| Acquisitions | – | | – | | – | | – | | – | |
| Disposals | 143 | | (13 | ) | – | | – | | 130 | |
| Actuarial gain on plan assetse | 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 | ) |
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|
|
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|
|
|
| Represented by | | | | | | | | | | |
| Asset recognized | 6,089 | | 617 | | – | | 47 | | 6,753 | |
| Liability recognized | (117 | ) | (357 | ) | (3,274 | ) | (5,528 | ) | (9,276 | ) |
|
|
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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 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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| | 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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|
|
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|
|
|
|
|
| a | The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions fund benefits are generally included in current service cost and the costs of administering our other post-retirement benefits are included in the benefit obligation. |
| b | Included within production and manufacturing expenses and distribution and administration expenses. |
| c | The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of a restructuring programme in the UK and Europe. |
| d | The benefit payments amount shown above comprises $2,266 million benefits plus $52 million of fund expenses incurred in the administration of the benefit. |
| e | 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
38 Pensions and other post-retirement benefits continued
| | | | | | | | | | $ million | |
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|
|
|
| | | | | | | | | | 2005 | |
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|
|
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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 costa | 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 operationsb | 383 | | 340 | | 42 | | 194 | | 959 | |
|
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|
|
|
|
|
|
|
|
| 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 | |
|
| a | The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions fund benefits are generally included in current service cost, and the costs of administering our other post-retirement benefits are included in the benefit obligation. |
| b | Included within production and manufacturing expenses and distribution and administration expenses. |
| | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| History of surplus (deficit) and of experience gains and losses | 2007 | | 2006 | | 2005 | | 2004 | | 2003 | |
|
|
|
|
|
|
|
|
|
|
|
| Benefit obligation at 31 December | 43,100 | | 42,433 | | 38,855 | | 39,945 | | 35,995 | |
| Fair value of plan assets at 31 December | 42,799 | | 39,910 | | 32,907 | | 31,712 | | 27,853 | |
|
|
|
|
|
|
|
|
|
|
|
| Surplus (deficit) | (301 | ) | (2,523 | ) | (5,948 | ) | (8,233 | ) | (8,142 | ) |
|
| Experience gains and losses on plan liabilities | (200 | ) | (124 | ) | (212 | ) | (468 | ) | 873 | |
| Actual return less expected return on pension plan assets | 302 | | 1,967 | | 3,364 | | 1,349 | | 2,392 | |
| Actual return on plan assets | 3,157 | | 4,377 | | 5,502 | | 3,332 | | 3,892 | |
| Actuarial gain recognized in statement of recognized income and expense | 1,717 | | 2,615 | | 975 | | 107 | | 76 | |
| Cumulative amount recognized in statement of recognized income and expense | 5,490 | | 3,773 | | 1,158 | | 183 | | 76 | |
|
Estimated future benefit payments
The expected benefit payments, which reflect expected future service, as appropriate, but exclude fund expenses, up until 2017 are as follows:
| | | | | | | | | | $ million | |
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|
|
|
|
|
|
|
|
|
|
| | | | | | US | | | | | |
| | UK | | US | | other post- | | | | | |
| | pension | | pension | | retirement | | | | | |
| | plans | | plans | | benefit plans | | Other plans | | Total | |
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|
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|
|
|
|
|
|
|
|
| 2008 | 1,112 | | 629 | | 224 | | 534 | | 2,499 | |
| 2009 | 1,183 | | 656 | | 227 | | 533 | | 2,599 | |
| 2010 | 1,252 | | 670 | | 235 | | 529 | | 2,686 | |
| 2011 | 1,334 | | 681 | | 240 | | 521 | | 2,776 | |
| 2012 | 1,378 | | 716 | | 242 | | 516 | | 2,852 | |
| 2013-2017 | 7,650 | | 3,301 | | 1,243 | | 2,551 | | 14,745 | |
|
Back to Contents
39 Called up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
|
| | | | | 2007 | | | | 2006 | | | | 2005 | |
|
|
| 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 | |
|
|
| | | | | 21 | | | | 21 | | | | 21 | |
|
|
| Ordinary shares of 25 cents each | | | | | | | | | | | | |
| | At 1 January | 21,457,301 | | 5,364 | | 20,657,045 | | 5,164 | | 21,525,978 | | 5,382 | |
| | Issue of new shares for employee share schemes | 69,273 | | 18 | | 64,854 | | 16 | | 82,144 | | 20 | |
| | Issue of ordinary share capital for TNK-BP | – | | – | | 111,151 | | 28 | | 108,629 | | 27 | |
| | Repurchase of ordinary share capital | (663,150 | ) | (166 | ) | (358,374 | ) | (90 | ) | (1,059,706 | ) | (265 | ) |
| | Othera | – | | – | | 982,625 | | 246 | | – | | – | |
|
|
| At 31 December | 20,863,424 | | 5,216 | | 21,457,301 | | 5,364 | | 20,657,045 | | 5,164 | |
|
|
| | | | | 5,237 | | | | 5,385 | | | | 5,185 | |
|
| 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 | |
|
| 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 663,149,528 ordinary shares (2006 1,334,362,750 and 2005 1,059,706,481 ordinary shares) for a total consideration of $7,497 million (2006 $15,481 million and 2005 $11,597 million), of which all were for cancellation. At 31 December 2007 150,966,096 (2006 99,045,000 and 2005 nil) ordinary shares bought back were awaiting cancellation. These shares have been excluded from ordinary shares in issue shown above. At 31 December 2007, 1,940,638,808 shares of nominal value $485 million were held in treasury (2006 1,946,804,533 shares of nominal value $487 million). The maximum number of shares held in treasury during the year was 1,946,804,533 shares of nominal value $487 million, representing 9.1% of the called up ordinary share capital of the company. During 2007, 1,700,000 treasury shares were gifted to the ESOP trust and 4,465,725 treasury shares were re-issued in relation to employee share schemes, in total representing less than 0.1% of the ordinary share capital of the company. The nominal value of these shares was $2 million and the total proceeds received were $35 million.
Transaction costs of share repurchases amounted to $40 million (2006 $83 million and 2005 $63 million).
Back to Contents
40 Capital and reserves
| | | | | | | | | |
|
| | | | | | | | | |
| | | | Share | | Capital | | | |
| | Share | | premium | | redemption | | Merger | |
| | capital | | account | | reserve | | reserve | |
|
| At 1 January 2007 | 5,385 | | 9,074 | | 839 | | 27,201 | |
| 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 pension and other post-retirement benefits (net of tax) | – | | – | | – | | – | |
| Available-for-sale investments marked to market (net of tax) | – | | – | | – | | – | |
| Available-for-sale investments recycling (net of tax) | – | | – | | – | | – | |
| Repurchase of ordinary share capital | (166 | ) | – | | 166 | | – | |
| Share-based payments (net of tax) | 18 | | 507 | | – | | 5 | |
| Cash flow hedges marked to market (net of tax) | – | | – | | – | | – | |
| Cash flow hedges recycling (net of tax) | – | | – | | – | | – | |
| Profit for the year | – | | – | | – | | – | |
| Dividends | – | | – | | – | | – | |
|
| At 31 December 2007 | 5,237 | | 9,581 | | 1,005 | | 27,206 | |
|
| | | | | | | | | |
|
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|
|
|
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|
|
|
| | | | | | | | | |
| | | | Share | | Capital | | | |
| | Share | | premium | | redemption | | Merger | |
| | capital | | account | | reserve | | reserve | |
|
| At 1 January 2006 | 5,185 | | 7,371 | | 749 | | 27,190 | |
| Currency translation differences (net of tax) | – | | – | | – | | – | |
| Actuarial gain relating to pension 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 | – | | – | | – | | – | |
| Otherb | 246 | | – | | – | | – | |
|
| At 31 December 2006 | 5,385 | | 9,074 | | 839 | | 27,201 | |
|
| |
|
| | | | Share | | Capital | | | |
| Share | premium | redemption | Merger |
| capital | account | reserve | reserve |
|
| At 31 December 2004 | 5,403 | | 5,636 | | 730 | | 27,162 | |
| Adoption of IAS 39 | – | | – | | – | | – | |
|
| 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 pension 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 | – | | – | | – | | – | |
|
| At 31 December 2005 | 5,185 | | 7,371 | | 749 | | 27,190 | |
|
| a | At 31 December 2006, the foreign currency translation reserve included $122 million relating to non-current assets held for sale. During 2007, this was included in the $147 million recycled to the income statement relating to disposals in 2007. For further details see Note 4. |
| b | Reclassification in respect of share repurchases in 2005. |
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| | | | | | | | | | | | | | | | | | | | | $ million | |
|
| | | | | | | 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 |
|
| 5 | | (154 | ) | (22,182 | ) | 4,685 | | 386 | | 39 | | 859 | | 58,487 | | 84,624 | | 841 | | 85,465 | |
| – | | – | | – | | 2,002 | | – | | – | | – | | – | | 2,002 | | 24 | | 2,026 | |
| – | | – | | – | | (147 | ) | – | | – | | – | | – | | (147 | ) | – | | (147 | ) |
| – | | – | | – | | – | | – | | – | | – | | 1,290 | | 1,290 | | – | | 1,290 | |
| – | | – | | – | | – | | 152 | | – | | – | | – | | 152 | | – | | 152 | |
| – | | – | | – | | – | | (57 | ) | – | | – | | – | | (57 | ) | – | | (57 | ) |
| – | | – | | – | | – | | – | | – | | – | | (7,997 | ) | (7,997 | ) | – | | (7,997 | ) |
| (5 | ) | 94 | | 70 | | – | | – | | – | | 337 | | (9 | ) | 1,017 | | – | | 1,017 | |
| – | | – | | – | | – | | – | | 138 | | – | | – | | 138 | | – | | 138 | |
| – | | – | | – | | – | | – | | (71 | ) | – | | – | | (71 | ) | – | | (71 | ) |
| – | | – | | – | | – | | – | | – | | – | | 20,845 | | 20,845 | | 324 | | 21,169 | |
| – | | – | | – | | – | | – | | – | | – | | (8,106 | ) | (8,106 | ) | (227 | ) | (8,333 | ) |
|
| – | | (60 | ) | (22,112 | ) | 6,540 | | 481 | | 106 | | 1,196 | | 64,510 | | 93,690 | | 962 | | 94,652 | |
|
| | | | | | | | | | | | | | | | | | | | | $ million | |
|
| | | | | | | 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 | a | investments | | hedges | | reserve | | account | | equity | interest | | equity | |
|
| 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 | ) | – | | – | | – | | – | | – | | – | | – | | – | |
|
| 5 | | (154 | ) | (22,182 | ) | 4,685 | | 386 | | 39 | | 859 | | 58,487 | | 84,624 | | 841 | | 85,465 | |
|
| | | | | | | | | | | | | | | | | | | | | $ million | |
|
|
| | | | | | | 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 | |
|
|
| 44 | | (82 | ) | – | | 5,616 | | – | | – | | 443 | | 31,940 | | 76,892 | | 1,343 | | 78,235 | |
| – | | – | | – | | – | | 230 | | (118 | ) | – | | (355 | ) | (243 | ) | – | | (243 | ) |
|
|
| 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 | ) |
|
|
| 16 | | (140 | ) | (10,598 | ) | 2,943 | | 385 | | (234 | ) | 643 | | 46,151 | | 79,661 | | 789 | | 80,450 | |
|
Back to Contents
40 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.
41 Share-based payments
| | | | | | $ million | |
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| Effect of share-based payment transactions on the group’s result and financial position | 2007 | | 2006 | | 2005 | |
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| Total expense recognized for equity-settled share-based payment transactions | 412 | | 405 | | 348 | |
| Total expense recognized for cash-settled share-based payment transactions | 16 | | 14 | | 20 | |
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| Total expense recognized for share-based payment transactions | 428 | | 419 | | 368 | |
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| Closing balance of liability for cash-settled share-based payment transactions | 40 | | 38 | | 48 | |
| Total intrinsic value for vested cash-settled share-based payments | 22 | | 23 | | 41 | |
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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 that vest (net of tax) are then subject to a three-year retention period. The director’s remuneration report on pages 62-72 includes full details of this plan.
Back to Contents
41 Share-based payments continued
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 62-72 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. The current policy of the company, which is reflected in the terms of the MTPP, is that senior employees subject to the plan should meet a minimum shareholding requirement.
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 retention 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, 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.
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 the 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 31/2years 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.
Back to Contents
41 Share-based payments continued
Savings and matching plans
BP ShareSave Plan
This is 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 a 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. 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
These are 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 more than 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. In certain countries, however, 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-settled share-based payments / 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/ restricted shares to the employee at the date of exercise or on maturity. The cash options/SARs have the same rules as the BPSOP plan and the cash restricted share plans (MTPP, DAB, PSP, RSP) have the same rules as their equity-settled counterparts.
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 to employees, the amount paid for those shares is deducted in arriving at shareholders’ equity. See Note 40. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.
At 31 December 2007, the ESOPs held 6,448,838 shares (2006 12,795,887 shares and 2005 14,560,003 shares) for potential future awards, which had a market value of $79 million (2006 $142 million and 2005 $156 million).
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| Share option transactions | | | 2007 | | | | 2006 | | | | 2005 | |
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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 | 426,471,462 | | 8.25 | | 450,453,502 | | 7.64 | | 470,263,808 | | 7.16 | |
| Granted during the year | 6,004,025 | | 9.11 | | 53,977,639 | | 11.18 | | 54,482,053 | | 10.24 | |
| Forfeited during the year | (3,924,714 | ) | 9.10 | | (7,169,710 | ) | 8.69 | | (4,844,827 | ) | 8.30 | |
| Exercised during the year | (69,715,558 | ) | 6.94 | | (70,658,480 | ) | 6.52 | | (68,687,976 | ) | 6.40 | |
| Expired during the year | (740,972 | ) | 8.68 | | (131,489 | ) | 7.99 | | (759,556 | ) | 6.75 | |
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| Outstanding at the end of the year | 358,094,243 | | 8.51 | | 426,471,462 | | 8.25 | | 450,453,502 | | 7.64 | |
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| Exercisable at the end of the year | 238,707,055 | | 7.70 | | 236,726,966 | | 7.41 | | 222,729,398 | | 7.54 | |
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As share options are exercised continuously throughout the year, the weighted average share price during the year of $11.72 (2006 $11.85 and 2005 $10.77) is representative of the weighted average share price at the date of exercise. For the options outstanding at 31 December 2007, 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 | 66,360,194 | | 3.88 | | 6.15 | | 55,509,664 | | 6.23 | |
| $6.80 – $8.50 | 162,364,928 | | 4.00 | | 8.02 | | 156,236,204 | | 8.04 | |
| $8.51 – $10.21 | 55,021,656 | | 4.89 | | 9.28 | | 26,961,187 | | 8.78 | |
| $10.22 – $11.92 | 74,347,465 | | 7.80 | | 11.13 | | – | | – | |
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| | 358,094,243 | | 4.90 | | 8.51 | | 238,707,055 | | 7.70 | |
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Back to Contents
41 Share-based payments continued
| Fair values and associated details for options and shares granted | | | | |
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| Options granted in 2007 | ShareSave 3 year | | ShareSave 5 year | |
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| Option pricing model used | Binomial | | Binomial | |
| Weighted average fair value | $3.57 | | $3.79 | |
| Weighted average share price | $12.10 | | $12.10 | |
| Weighted average exercise price | $9.13 | | $9.13 | |
| Expected volatility | 21% | | 21% | |
| Option life | 3.5 years | | 5.5 years | |
| Expected dividends | 3.48% | | 3.48% | |
| Risk free interest rate | 5.75% | | 5.75% | |
| Expected exercise behaviour | 100% year 4 | | 100% year 6 | |
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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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The group uses an appropriate valuation model of expected volatility of US ADSs for the quarter within which the grant date of the relevant plan falls. Management is responsible for all inputs and assumptions in relation to that model, including the determination of expected volatility.
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| | MTPP- | | MTPP- | | EDIP- | | EDIP- | | | | | | | |
| Shares granted in 2007 | TSR | | FCF | | TSR | | LTL | | RSP | | DAB | | PSP | |
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| Number of equity instruments granted (million) | 9.4 | | 8.5 | | 4.5 | | 0.5 | | 7.7 | | 4.4 | | 14.8 | |
| Weighted average fair value | $4.73 | | $10.02 | | $2.81 | | $9.92 | | $11.93 | | $10.02 | | $12.37 | |
| Fair value measurement basis | Monte Carlo | | Market value | | Monte Carlo | | Market value | | Market value | | Market value | | Monte Carlo | |
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| | | | MTPP- | | MTPP- | | EDIP- | | EDIP- | | | | | |
| Shares granted in 2006 | | | TSR | | FCF | | TSR | | LTL | | RSP | | DAB | |
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| Number of equity instruments granted (million) | | | 8.7 | | 7.8 | | 3.3 | | 0.5 | | 0.5 | | 3.5 | |
| Weighted average fair value | | | $7.28 | | $11.23 | | $4.87 | | $11.23 | | $11.07 | | $11.06 | |
| Fair value measurement basis | | | Monte Carlo | | Market value | | Monte Carlo | | Market value | | 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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The group used a Monte Carlo simulation to fair value the TSR element of the 2007, 2006 and 2005 PSP, 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.
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.
Back to Contents
42 Employee costs and numbers
| | | | $ million | |
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| Employee costs | 2007 | 2006 | 2005 | |
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| Wages and salariesa | 9,560 | 8,411 | 8,695 | |
| Social security costs | 771 | 751 | 754 | |
| Share-based payments | 428 | 419 | 368 | |
| Pension and other post-retirement benefit costs | 504 | 770 | 929 | |
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| | 11,263 | 10,351 | 10,746 | |
| Innovene operations | – | – | (892 | ) |
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| Continuing operations | 11,263 | 10,351 | 9,854 | |
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| Number of employees at 31 December | 2007 | 2006 | 2005 | |
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| Exploration and Production | 19,800 | 19,000 | 17,000 | |
| Refining and Marketingb | 69,000 | 69,500 | 70,800 | |
| Gas, Power and Renewables | 4,500 | 4,500 | 4,100 | |
| Other businesses and corporate | 4,300 | 4,000 | 4,300 | |
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| | 97,600 | 97,000 | 96,200 | |
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| By geographical area | | | | |
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| UK | 17,000 | 16,900 | 16,500 | |
| Rest of Europe | 19,900 | 20,200 | 21,300 | |
| US | 33,000 | 33,700 | 34,400 | |
| Rest of World | 27,700 | 26,200 | 24,000 | |
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| | 97,600 | 97,000 | 96,200 | |
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| | | Rest of | | Rest of | | | Rest of | | Rest of | | |
| Average number of employees | UK | Europe | US | World | Total | UK | Europe | US | World | Total | |
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| Exploration and Production | 3,700 | 700 | 6,600 | 8,700 | 19,700 | 3,300 | 700 | 6,100 | 8,100 | 18,200 | |
| Refining and Marketing | 10,600 | 18,600 | 23,500 | 16,300 | 69,000 | 11,300 | 19,300 | 24,900 | 15,000 | 70,500 | |
| Gas, Power and Renewables | 300 | 700 | 1,800 | 1,500 | 4,300 | 300 | 700 | 1,600 | 1,700 | 4,300 | |
| Other businesses and corporate | 2,100 | 200 | 1,700 | 200 | 4,200 | 1,900 | 200 | 1,900 | 100 | 4,100 | |
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| | 16,700 | 20,200 | 33,600 | 26,700 | 97,200 | 16,800 | 20,900 | 34,500 | 24,900 | 97,100 | |
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| Average number of employees | UK | Europe | US | World | Total | |
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| Exploration and Production | 3,000 | 600 | 5,300 | 7,300 | 16,200 | |
| Refining and Marketing | 11,100 | 19,700 | 26,200 | 14,000 | 71,000 | |
| Gas, Power and Renewables | 200 | 800 | 1,500 | 1,400 | 3,900 | |
| Other businesses and corporate | 3,800 | 3,900 | 3,600 | 300 | 11,600 | |
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| | 18,100 | 25,000 | 36,600 | 23,000 | 102,700 | |
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| a | Includes termination payments of $422 million (2006 $257 million and 2005 $348 million). A restructuring was announced in October 2007, the implementation of which is expected to continue through 2008 and into 2009. Additional restructuring charges to the income statement of around $1 billion are expected in 2008. |
| b | Includes 25,900 (2006 26,100 and 2005 27,800) service station staff. |
43 Remuneration of directors and senior management
| Remuneration of directors | | | $ million | |
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| | | 2007 | 2006 | 2005 | |
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| Total for all directors | | | | |
| | Emoluments | 26 | 14 | 18 | |
| | Gains made on the exercise of share options | 2 | 12 | – | |
| | Amounts awarded under incentive schemes | 10 | 14 | 8 | |
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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. This includes an ex gratia superannuation payment of $3 million (2006 and 2005 nil) and compensation for loss of office of $1 million (2006 and 2005 nil).
Pension contributions
Six executive directors participated in a non-contributory pension scheme established for UK employees 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 2007.
Back to Contents
43 Remuneration of directors and senior management continued
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 62-72.
| Remuneration of senior management | | | | | $ million | |
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| | | 2007 | | 2006 | | 2005 | |
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| Total for all senior management | | | | | | |
| | Short-term employee benefits | 37 | | 30 | | 25 | |
| | Post-retirement benefits | 7 | | 4 | | 4 | |
| | Share-based payments | 22 | | 26 | | 27 | |
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Senior management, in addition to executive and non-executive directors, includes other senior managers who are members of the executive management team.
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. This includes an ex gratia superannuation payment of $3 million (2006 and 2005 nil) and compensation for loss of office of $1 million (2006 $5 million, 2005 nil).
Post-retirement benefits
The amounts represent the estimated cost to the group of providing defined benefit pensions and other post-retirement benefits to senior 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 senior 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 senior management have participated are the EDIP, MTPP and LTPP. For details of these plans refer to Note 41.
44 Contingent liabilities
There were contingent liabilities at 31 December 2007 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. Further information is included in Note 28.
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. It is not possible to estimate any financial effect.
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 files income tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group’s income tax returns. Tax returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is difficult to predict the ultimate outcome in some cases, the group does not anticipate that there will be any material impact on the group’s results of operations, financial position or liquidity.
Back to Contents
44 Contingent liabilities continued
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, it is not practical to estimate the amounts involved. 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.
45 Capital commitments
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been placed at 31 December 2007 amounted to $8,263 million (2006 $9,773 million). In addition, at 31 December 2007, the group had contracts in place for future capital expenditure relating to investments in jointly controlled entities of $1,039 million (2006 $32 million) and investments in associates of $74 million (2006 $36 million).
Capital commitments of jointly controlled entities amounted to $2,273 million (2006 $1,217 million).
Back to Contents
46 Subsidiaries, jointly controlled entities and associates
The more important subsidiaries, jointly controlled entities and associates of the group at 31 December 2007 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 Investments | 100 | | England | Petrochemicals | | BP Capital | | | 100 | | Netherlands | | | Finance |
| *BP Corporate Holdings | 100 | | England | Investment holding | | 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 |
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| 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 |
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| 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 |
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| 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 |
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| Azerbaijan | | | | | | US | | | | | | | | |
| Amoco Caspian Sea | | | British Virgin | Exploration and production | | *BP Holdings North | | | | | | | | |
| Petroleum | 100 | | Islands | | | America | | | 100 | | England | | | Investment holding |
| BP Exploration | | | | | | Atlantic Richfield Co. | | | | | | | | |
| (Caspian Sea) | 100 | | England | Exploration and production | | BP America | | | | | | |
| | | | | | | BP America | | | | | | |
| Canada | | | | | | Production Company | | | | | | |
| BP Canada Energy | 100 | | Canada | Exploration and production | | BP Amoco Chemical | | | | | | |
| BP Canada Finance | 100 | | Canada | Finance | | Company | | | | | | |
| | | | | | | BP Company | | | | | | Exploration and production, |
| Egypt | | | | | | North America | | | | | | gas, power and renewables, |
| BP Egypt Co. | 100 | | US | Exploration and production | | BP Corporation | | 100 | | US | | refining and marketing, |
| BP Egypt Gas Co. | 100 | | US | Exploration and production | | North America | | | | pipelines and |
| | | | | | | BP Exploration (Alaska) | | | | | | petrochemicals |
| Germany | | | | | | Inc. | | | | | | |
| Deutsche BP | 100 | | Germany | Refining and marketing | | BP Products | | | | | | |
| | | | | and petrochemicals | | North America | | | | | | |
| | | | | | | BP West Coast | | | | | | |
| Indonesia | | | | | | Products | | | | | | |
| BP Berau | 100 | | US | Exploration and production | | Standard Oil Co. | | | | | | |
| BP West Java | 100 | | US | Exploration and production | | BP Capital Markets | | | | | | |
| | | | | | | America | | | | | | | Finance |
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Back to Contents
46 Subsidiaries, jointly controlled entities and associates continued
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| 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 |
| Elvary Neftegaz Holdings BV | 49 | | Netherlands | Exploration and appraisal |
| 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 therefore 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
47 Oil and natural gas exploration and production activitiesa
| | | | | | | | | | | | | | | | | | | $ million | |
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| | | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | | UK | | Europe | | US | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Capitalized costs at 31 December | | | | | | | | | | | | | | | | | | |
| Gross capitalized costs | | | | | | | | | | | | | | | | | | |
| | Proved properties | 34,774 | | 4,925 | | 53,079 | | 10,627 | | 3,528 | | 18,333 | | – | | 7,596 | | 132,862 | |
| | Unproved properties | 606 | | – | | 1,660 | | 297 | | 1,188 | | 1,533 | | 4 | | 349 | | 5,637 | |
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| | | 35,380 | | 4,925 | | 54,739 | | 10,924 | | 4,716 | | 19,866 | | 4 | | 7,945 | | 138,499 | |
| Accumulated depreciation | 25,515 | | 2,925 | | 25,500 | | 5,528 | | 1,508 | | 8,315 | | – | | 2,553 | | 71,844 | |
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| Net capitalized costs | 9,865 | | 2,000 | | 29,239 | | 5,396 | | 3,208 | | 11,551 | | 4 | | 5,392 | | 66,655 | |
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The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2007 was $11,787 million.
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| Costs incurred for the year ended 31 December | |
| Acquisition of properties | | | | | | | | | | | | | | | | | | |
| | Proved | – | | – | | 245 | | – | | – | | – | | – | | 232 | | 477 | |
| | Unproved | – | | – | | 54 | | 16 | | – | | 321 | | – | | 126 | | 517 | |
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| | | – | | – | | 299 | | 16 | | – | | 321 | | – | | 358 | | 994 | |
| Exploration and appraisal costsb | 209 | | 16 | | 646 | | 72 | | 51 | | 677 | | 119 | | 102 | | 1,892 | |
| Development costs | 804 | | 443 | | 3,861 | | 1,057 | | 333 | | 2,634 | | – | | 1,021 | | 10,153 | |
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| Total costs | 1,013 | | 459 | | 4,806 | | 1,145 | | 384 | | 3,632 | | 119 | | 1,481 | | 13,039 | |
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The group’s share of jointly controlled entities’ and associates’ costs incurred in 2007 was $2,552 million: in Russia $1,787 million, Rest of Americas $569 million, Asia Pacific $17 million and other $179 million.
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| Results of operations for the year ended 31 December | | | | | | | | | | | | | | | | | |
| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| | Third parties | 4,503 | | 434 | | 1,436 | | 2,142 | | 1,148 | | 2,219 | | – | | 921 | | 12,803 | |
| | Sales between businesses | 2,260 | | 902 | | 14,353 | | 3,142 | | 970 | | 3,223 | | – | | 9,983 | | 34,833 | |
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| | | 6,763 | | 1,336 | | 15,789 | | 5,284 | | 2,118 | | 5,442 | | – | | 10,904 | | 47,636 | |
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| Exploration expenditure | 46 | | – | | 252 | | 134 | | 11 | | 183 | | 116 | | 14 | | 756 | |
| Production costs | 1,658 | | 147 | | 2,782 | | 770 | | 190 | | 637 | | 2 | | 344 | | 6,530 | |
| Production taxes | 227 | | 3 | | 1,260 | | 273 | | 56 | | – | | – | | 2,224 | | 4,043 | |
| Other costs (income) | (419 | ) | 123 | | 2,505 | | 395 | | 378 | | 200 | | 169 | | 3,018 | | 6,369 | |
| Depreciation, depletion and amortization | 1,569 | | 207 | | 2,118 | | 822 | | 205 | | 1,372 | | – | | 995 | | 7,288 | |
| Impairments and (gains) losses on sale of | | | | | | | | | | | | | | | | | | |
| | businesses and fixed assets | 112 | | (534 | ) | (413 | ) | (43 | ) | – | | (76 | ) | – | | – | | (954 | ) |
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| | | 3,193 | | (54 | ) | 8,504 | | 2,351 | | 840 | | 2,316 | | 287 | | 6,595 | | 24,032 | |
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| Profit before taxationc,d | 3,570 | | 1,390 | | 7,285 | | 2,933 | | 1,278 | | 3,126 | | (287 | ) | 4,309 | | 23,604 | |
| Allocable taxes | 1,664 | | 611 | | 2,560 | | 1,202 | | 321 | | 1,462 | | 3 | | 1,079 | | 8,902 | |
|
|
| Results of operations | 1,906 | | 779 | | 4,725 | | 1,731 | | 957 | | 1,664 | | (290 | ) | 3,230 | | 14,702 | |
|
The group’s share of jointly controlled entities’ and associates’ results of operations (including the group’s share of total TNK-BP results) in 2007 was a profit of $2,704 million after deducting interest of $401 million, taxation of $1,355 million and minority interest of $215 million.
| a | This note contains information relating to oil and natural gas exploration and production activities. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia. The group’s share of jointly controlled entities’ and associates’ acitivies are excluded from the tables and included in the footnotes with the exception of the Abu Dhabi operations, which are included in the results of operations 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 | Includes property taxes, other government take and the fair value gain on embedded derivatives of $47 million. The UK Region includes a $409 million gain offset by corresponding charges primarily in the US, relating to the group self-insurance programme. |
| d | The Exploration and Production profit before interest and tax is set out below. |
| | |
| | $ million | |
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| | 2007 | |
|
| Exploration and production activities | | | | | | | | | | | | | | | | | | |
| Group (as above) | 3,570 | | 1,390 | | 7,285 | | 2,933 | | 1,278 | | 3,126 | | (287 | ) | 4,309 | | 23,604 | |
| Jointly controlled entities and associates | – | | – | | 1 | | 381 | | 21 | | – | | 2,292 | | 9 | | 2,704 | |
| Mid-stream activities | 123 | | (7 | ) | 472 | | 42 | | 6 | | (10 | ) | (112 | ) | 116 | | 630 | |
|
| Total profit before interest and tax | 3,693 | | 1,383 | | 7,758 | | 3,356 | | 1,305 | | 3,116 | | 1,893 | | 4,434 | | 26,938 | |
|
Back to Contents
47 Oil and natural gas exploration and production activitiesacontinued
| | | | | | | | | | | | | | | | | | | $ million | |
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| | | | | | | | | | | | | | | | | | | 2006 | |
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| | | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | | UK | | Europe | | US | | 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 | |
|
| | | 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 | |
|
| Net capitalized costs | 10,043 | | 1,892 | | 26,575 | | 5,165 | | 3,015 | | 9,508 | | 1 | | 4,707 | | 60,906 | |
|
The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2006 was $10,870 million.
|
| Costs incurred for the year ended 31 December | |
| Acquisition of properties | | | | | | | | | | | | | | | | | | |
| | Proved | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| | Unproved | – | | – | | 74 | | 8 | | 2 | | 70 | | – | | – | | 154 | |
|
| | | – | | – | | 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 | |
|
| Total costs | 926 | | 240 | | 4,491 | | 963 | | 285 | | 2,860 | | 73 | | 1,190 | | 11,028 | |
|
The group’s share of jointly controlled entities’ and associates’ costs incurred in 2006 was $1,688 million: in Russia $1,109 million, Rest of Americas $424 million, Asia Pacific $16 million and other $139 million.
|
|
| Results of operations for the year ended 31 December | |
| Sales and other operating revenues | | | | | | | | | | | | | | | | | | |
| | 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 | |
|
|
| | | 7,707 | | 1,652 | | 15,953 | | 5,425 | | 1,966 | | 4,522 | | – | | 8,408 | | 45,633 | |
|
|
| 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)c | (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 | ) |
|
|
| | | 2,119 | | 428 | | 6,596 | | 2,270 | | 459 | | 1,579 | | 49 | | 6,048 | | 19,548 | |
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| |
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| Profit before taxationd,e | 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 | |
| |
| Results of operations | 3,021 | | 431 | | 6,221 | | 1,712 | | 1,035 | | 1,615 | | (52 | ) | 1,623 | | 15,606 | |
|
The group’s share of jointly controlled entities’ and associates’ results of operations (including the group’s share of total TNK-BP results) 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. Midstream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main midstream 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 | 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. |
| d | 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. |
| e | The Exploration and Production profit before interest and tax is set out below. |
| | | | | | | | | | | | | | | | | | | | |
| | | $ 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
47 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 | | US | | 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 revenues | | | | | | | | | | | | | | | | | | |
| | 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)c | 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 taxationd,e | 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 (including the group’s share of total TNK-BP results) 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. Midstream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main midstream 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 | 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. |
| d | 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. |
| e | 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
Additional information for US reporting
BP has taken advantage of the SEC ruling of 15 November 2007 that eliminated the requirement to provide a reconciliation from IFRS to US GAAP.
48 Suspended exploration well costs
Included within the total exploration expenditure of $5,252 million (2006 $4,110 million and 2005 $4,008 million) shown as part of intangible assets (see Note 25) is an amount of $2,342 million (2006 $1,863 million and 2005 $1,931 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 per 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: (i) that exploration drilling is still under way or firmly planned, or (ii) that it has been determined, or work is under way 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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| | | 2007 | | 2006 | | 2005 | |
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| Capitalized exploration well costs | | | | | | | |
| At 1 January | | 1,863 | | 1,931 | | 1,680 | |
| Additions pending determination of proved reserves | | 773 | | 590 | | 565 | |
| Exploration well costs written off in the year | | (94 | ) | (168 | ) | (81 | ) |
| Costs of exploration wells divested in the year | | (27 | ) | (36 | ) | (72 | ) |
| Reclassified to tangible assets following determination of proved reserves | | (173 | ) | (251 | ) | (161 | ) |
| Reclassified to investment in jointly controlled entity | | – | | (203 | ) | – | |
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| At 31 December | | 2,342 | | 1,863 | | 1,931 | |
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The following table provides an ageing profile of suspended exploration wells.
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| At 31 December | | | | 2007 | | | | 2006 | | | | 2005 | |
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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 | | 761 | | 35 | | 611 | | 45 | | 593 | | 46 | |
| 1 to 5 years | | 1,081 | | 73 | | 736 | | 64 | | 823 | | 69 | |
| 6 to 10 years | | 224 | | 30 | | 267 | | 37 | | 309 | | 42 | |
| More than 10 years | | 276 | | 35 | | 249 | | 26 | | 206 | | 20 | |
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| Total | | 2,342 | | 173 | | 1,863 | | 172 | | 1,931 | | 177 | |
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The following table provides an analysis of the amount of drilling costs directly associated with exploration wells.
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| | | | | | | 2007 | | | | | | 2006 | | | | | | 2005 | |
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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 | | | | | | | | | | | | | | | | | | | |
Projects with first capitalized exploration well
drilled in the 12 months ending 31 December | | 168 | | 11 | | 7 | | 188 | | 17 | | 12 | | 451 | | 31 | | 14 | |
| Other projects with recent or planned drilling activity | | 1,502 | | 92 | | 24 | | 894 | | 86 | | 21 | | 718 | | 65 | | 20 | |
| Projects with completed exploration activity | | 672 | | 70 | | 27 | | 781 | | 69 | | 27 | | 762 | | 81 | | 28 | |
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| At 31 December | | 2,342 | | 173 | | 58 | | 1,863 | | 172 | | 60 | | 1,931 | | 177 | | 62 | |
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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 51 projects that have exploration well costs that have been capitalized for more than twelve months as at 31 December 2007. Of these, there are 24 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 $672 million at 31 December 2007. Details of the activities being undertaken to progress these projects towards development are shown below.
Back to Contents
48 Suspended exploration well costs continued
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| | | | | | | | | | | Anticipated | | | |
| | | | | | | 2007 | | 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 | | 2011-2014 | | Assessment of hydrocarbon quantities as potentially commercial completed; development option identified and under evaluation; development plan for FPSO submitted. | |
| | | Plutao/Saturno/Marte/Venus | | 51 | | 5 | | 2002-2005 | | 2008 | | Assessment of hydrocarbon quantities as potentially commercial completed; development option using FPSO identified and under evaluation. | |
| | | Cravo/Lirio/Orquidea/Violeta | | 32 | | 7 | | 1998-2006 | | 2009 | | Assessment of hydrocarbon quantities as potentially commercial completed; development option using FPSO identified and under evaluation. | |
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| | | | | 109 | | 14 | | | | | | | |
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| Egypt | | Ras El Bar Seth | | 3 | | 1 | | 1995 | | 2008 | | Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; development planned through tie-back to existing infrastructure; gas sale agreement in place. | |
| | | Western Mediterranean
Block B | | 13 | | 3 | | 2002-2004 | | 2008-2010 | | Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; seismic survey completed and under review; concession agreement amendment negotiations under way. | |
| | | East Delta Deep Marine | | 11 | | 2 | | 2002-2006 | | 2011 | | Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation involving tie-back to existing infrastructure. | |
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| | | | | 27 | | 6 | | | | | | | |
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| Indonesia | | Tangguh Phase II | | 51 | | 9 | | 1994-1997 | | 2009-2011 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; onshore and offshore development options identified and under evaluation. This is the second phase of the LNG project that is currently under development. | |
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| | | | | 51 | | 9 | | | | | | | |
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| Trinidad | | Coconut | | 47 | | 1 | | 2005 | | 2014 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; development options identified and under evaluation; planned subsea tie-back to existing infrastructure. | |
| | | Corallita/Lantana | | 24 | | 2 | | 1996 | | 2008 | | Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; planned subsea tie-back to existing infrastructure fields dedicated to LNG gas contract delivery; dependent upon capacity in existing infrastructure. | |
| | | Manakin | | 22 | | 1 | | 2000 | | 2011 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; development options identified and under evaluation; planned subsea tie-back to existing production facilities and LNG train; inter-governmental discussions on unitization continue. | |
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| | | | | 93 | | 4 | | | | | | | |
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Back to Contents
48 Suspended exploration well costs continued
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| | | | | | | | | | | Anticipated | | | |
| | | | | | | 2007 | | Years | | year of | | | |
| | | | | Cost | | wells | | wells | | development | | | |
| Country | | Project | | $ million | | gross | | drilled | | project sanction | | Comment | |
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| UK | | Andrew | | 14 | | 1 | | 1998 | | 2008 | | Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; development awaiting capacity in existing infrastructure; negotiations under way for gas sales contract. | |
| | | Devenick | | 90 | | 3 | | 1983-2001 | | 2008-2009 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in progress; development options identified and under evaluation; development may be in conjunction with Harding Gas project nearby. | |
| | | Puffin | | 29 | | 9 | | 1982-1991 | | 2009-2010 | | Assessment of hydrocarbon quantities as potentially commercial completed; further assessment of economic and developmental aspects of project to be undertaken; sub-surface and feasibility review under way; development awaiting capacity in existing infrastructure. | |
| | | Kessog | | 35 | | 4 | | 1986-1987 | | 2010 | | Assessment of hydrocarbon quantities as potentially commercial completed; further assessment of economic and developmental aspects of project in progress. | |
| | | Suilven | | 20 | | 3 | | 1995-1998 | | 2010-2011 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic and developmental aspects of project in progress; development anticipated to be by tie-back to existing production vessel; awaiting capacity in existing infrastructure. | |
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| | | | | 188 | | 20 | | | | | | | |
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| US | | Liberty | | 20 | | 1 | | 1997 | | 2008 | | Assessment of hydrocarbon quantities as potentially commercial completed; development options identified and under evaluation; planned tie-back via extended reach drilling from existing infrastructure; memoranda of understanding with two key permitting agencies have been secured. | |
| | | Mad Dog Deep | | 48 | | 1 | | 2005 | | 2009-2011 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic and developmental aspects of project under way. | |
| | | Mad Dog Southwest Ridge | | 34 | | 3 | | 2005 | | 2010 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project under way; development options identified and under evaluation; development expected to be by subsea tieback. | |
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| | | | | 102 | | 5 | | | | | | | |
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| Vietnam | | Hai Thach | | 65 | | 3 | | 1995-2002 | | 2009 | | Assessment of hydrocarbon quantities as potentially commercial completed; assessment of economic aspects of project in place; development options identified and under evaluation; licence extension secured. | |
| | | Kim Cuong Tay | | 13 | | 1 | | 1995 | | 2010-2012 | | Initial assessment of hydrocarbon quantities as potentially commercial completed; further assessment of developmental aspects of project to be undertaken; further seismic study planned for 2008. | |
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| | | | | 78 | | 4 | | | | | | | |
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| Miscellaneous smaller projects | | 24 | | 8 | | | | | | | |
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| | | | | 672 | | 70 | | | | | | | |
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| Certain projects that were classified as projects with completed exploration drilling activity at 31 December 2006 are not classified as such at 31 December 2007: |
| – | The following projects were sanctioned for development in 2007: Skarv in Norway and Chachalaca in Trinidad & Tobago. |
| – | In Colombia, $43 million relating to the Volcanera project was written off. |
| – | In the US, the Entrada field was disposed of. |
Back to Contents
49 Auditors’ remuneration for US reporting
| | | | | | $ million | |
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| Audit fees – Ernst & Young | | | | | | |
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| Group audit | 37 | | 36 | | 31 | |
| Audit-related regulatory reporting | 7 | | 9 | | 6 | |
| Statutory audit of subsidiaries | 19 | | 19 | | 23 | |
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| | 63 | | 64 | | 60 | |
| Innovene operations | – | | – | | (8 | ) |
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| Continuing operations | 63 | | 64 | | 52 | |
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| Fees for other services – Ernst & Young | | | | | | |
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| Further assurance services | | | | | | |
| Acquisition and disposal due diligence | 1 | | 3 | | 2 | |
| Pension plan audits | 1 | | – | | 1 | |
| Other further assurance services | 8 | | 5 | | 23 | |
| Tax services | | | | | | |
| Compliance services | – | | 1 | | 10 | |
| Advisory services | 2 | | – | | – | |
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| | 12 | | 9 | | 36 | |
| Innovene operations | – | | – | | (1 | ) |
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| Continuing operations | 12 | | 9 | | 35 | |
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Audit fees for 2007 include $7 million of additional fees for 2006 (2006 $5 million of additional fees for 2005 and 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 $1 million (2006 $nil and 2005 $4 million) in respect of advice on accounting, auditing and financial reporting matters; $nil (2006 $nil and 2005 $16 million) in respect of internal accounting and risk management control reviews; $5 million (2006 $5 million and 2005 $3 million) in respect of non-statutory audits and $2 million (2006 $nil and 2005 $nil) in respect of project assurance and advice on business and accounting process improvement.
The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory 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 with that of other potential service providers. These services are for a fixed term.50 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 | | accounts | a | Deductions | | 31 December | |
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| 2007 | | | | | | | | | | |
| Fixed assets – Investmentsb | 151 | | 158 | | 2 | | (165 | ) | 146 | |
| Doubtful debtsb | 421 | | 175 | | 34 | | (224 | ) | 406 | |
| 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 | |
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| a | Principally currency transactions. |
| b | Deducted in the balance sheet from the assets to which they apply. |
Back to Contents
51 Computation of ratio of earnings to fixed charges (unaudited)
| | | | | | | | $ million, except ratios | |
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| For the year ended 31 December | 2007 | | 2006 | | 2005 | | 2004 | | 2003 | |
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| Profit before taxation | 31,611 | | 35,142 | | 31,421 | | 24,966 | | 17,731 | |
| Group’s share of income in excess of dividends from equity-accounted entities | (1,359 | ) | – | | (710 | ) | (81 | ) | (666 | ) |
| Capitalized interest, net of amortization | (183 | ) | (341 | ) | (193 | ) | (133 | ) | (123 | ) |
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| | 30,069 | | 34,801 | | 30,518 | | 24,752 | | 16,942 | |
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| Fixed charges | | | | | | | | | | |
| Interest expense | 1,110 | | 718 | | 559 | | 440 | | 482 | |
| Rental expense representative of interest | 1,033 | | 946 | | 605 | | 619 | | 460 | |
| Capitalized interest | 323 | | 478 | | 351 | | 204 | | 190 | |
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| | 2,466 | | 2,142 | | 1,515 | | 1,263 | | 1,132 | |
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| Total adjusted earnings available for payment of fixed charges | 32,535 | | 36,943 | | 32,033 | | 26,015 | | 18,074 | |
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| Ratio of earnings to fixed charges | 13.2 | | 17.2 | | 21.1 | | 20.6 | | 16.0 | |
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52 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., and 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 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.
| Income statement | | | | | | | | | $ million | |
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| For the year ended 31 December | | | | | | | | | 2007 | |
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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 | 5,243 | | – | | 284,365 | | (5,243 | ) | 284,365 | |
| Earnings from jointly controlled entities – after interest and tax | – | | – | | 3,135 | | – | | 3,135 | |
| Earnings from associates – after interest and tax | – | | – | | 697 | | – | | 697 | |
| Equity-accounted income of subsidiaries – after interest and tax | 586 | | 21,201 | | – | | (21,787 | ) | – | |
| Interest and other revenues | 758 | | 205 | | 377 | | (586 | ) | 754 | |
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| Total revenues | 6,587 | | 21,406 | | 288,574 | | (27,616 | ) | 288,951 | |
| Gains on sale of businesses and fixed assets | 1 | | – | | 2,486 | | – | | 2,487 | |
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| Total revenues and other income | 6,588 | | 21,406 | | 291,060 | | (27,616 | ) | 291,438 | |
| Purchases | 650 | | – | | 205,359 | | (5,243 | ) | 200,766 | |
| Production and manufacturing expenses | 897 | | – | | 25,018 | | – | | 25,915 | |
| Production and similar taxes | 1,052 | | – | | 2,961 | | – | | 4,013 | |
| Depreciation, depletion and amortization | 388 | | – | | 10,191 | | – | | 10,579 | |
| Impairment and losses on sale of businesses and fixed assets | – | | – | | 1,679 | | – | | 1,679 | |
| Exploration expense | – | | – | | 756 | | – | | 756 | |
| Distribution and administration expenses | 22 | | 921 | | 14,536 | | (108 | ) | 15,371 | |
| Fair value (gain) loss on embedded derivatives | – | | – | | 7 | | – | | 7 | |
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| Profit before interest and taxation | 3,579 | | 20,485 | | 30,553 | | (22,265 | ) | 32,352 | |
| Finance costs | – | | 381 | | 1,207 | | (478 | ) | 1,110 | |
| Other finance expense (income) | 49 | | (820 | ) | 402 | | – | | (369 | ) |
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| Profit before taxation | 3,530 | | 20,924 | | 28,944 | | (21,787 | ) | 31,611 | |
| Taxation | 1,081 | | 79 | | 9,282 | | – | | 10,442 | |
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| Profit for the year | 2,449 | | 20,845 | | 19,662 | | (21,787 | ) | 21,169 | |
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| Attributable to | | | | | | | | | | |
| BP shareholders | 2,449 | | 20,845 | | 19,338 | | (21,787 | ) | 20,845 | |
| Minority interest | – | | – | | 324 | | – | | 324 | |
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| | 2,449 | | 20,845 | | 19,662 | | (21,787 | ) | 21,169 | |
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Back to Contents
52 Condensed consolidating information on certain US subsidiaries continued
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| Income statement (continued) | | | | | | | | | $ 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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| 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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| 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 | ) |
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| 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 | ) |
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| 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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| | 2,193 | | 22,420 | | 21,782 | | (23,794 | ) | 22,601 | |
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| Income statement | | | | | | | | | $ 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 | |
|
|
|
|
|
|
|
|
|
|
|
| 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 | |
|
|
|
|
|
|
|
|
|
|
|
| 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 | |
|
|
|
|
|
|
|
|
|
|
|
| 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 | |
|
|
|
|
|
|
|
|
|
|
|
| Profit before taxation from continuing operations | 3,818 | | 22,035 | | 28,399 | | (22,831 | ) | 31,421 | |
| Taxation | 1,138 | | 9 | | 8,141 | | – | | 9,288 | |
|
|
|
|
|
|
|
|
|
|
|
| Profit from continuing operations | 2,680 | | 22,026 | | 20,258 | | (22,831 | ) | 22,133 | |
| Profit (loss) from Innovene operations | – | | – | | 184 | | – | | 184 | |
|
|
|
|
|
|
|
|
|
|
|
| Profit for the year | 2,680 | | 22,026 | | 20,442 | | (22,831 | ) | 22,317 | |
|
| Attributable to | | | | | | | | | | |
| BP shareholders | 2,680 | | 22,026 | | 20,151 | | (22,831 | ) | 22,026 | |
| Minority interest | – | | – | | 291 | | – | | 291 | |
|
|
|
|
|
|
|
|
|
|
|
| | 2,680 | | 22,026 | | 20,442 | | (22,831 | ) | 22,317 | |
|
Back to Contents
| 178 | |
|
| |
| 52 Condensed consolidating information on certain US subsidiaries continued |
| | | | | | | | | | | |
| Balance sheet | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| At 31 December | | | | | | | | | 2007 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | | Other | | and | | | |
| | (Alaska) Inc. | | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| Non-current assets | | | | | | | | | | |
| Property, plant and equipment | 6,310 | | – | | 91,679 | | – | | 97,989 | |
| Goodwill | – | | – | | 11,006 | | – | | 11,006 | |
| Intangible assets | 349 | | – | | 6,303 | | – | | 6,652 | |
| Investments in jointly controlled entities | – | | – | | 18,113 | | – | | 18,113 | |
| Investments in associates | – | | 2 | | 4,577 | | – | | 4,579 | |
| Other investments | – | | – | | 1,830 | | – | | 1,830 | |
| Subsidiaries – equity-accounted basis | 3,117 | | 115,476 | | – | | (118,593 | ) | – | |
|
|
|
|
|
|
|
|
|
|
|
| Fixed assets | 9,776 | | 115,478 | | 133,508 | | (118,593 | ) | 140,169 | |
| Loans | 2,151 | | 1,192 | | 1,541 | | (3,885 | ) | 999 | |
| Other receivables | – | | – | | 968 | | – | | 968 | |
| Derivative financial instruments | – | | – | | 3,741 | | – | | 3,741 | |
| Prepayments | – | | – | | 1,083 | | – | | 1,083 | |
| Defined benefit pension plan surplus | – | | 7,265 | | 1,649 | | – | | 8,914 | |
|
|
|
|
|
|
|
|
|
|
|
| | 11,927 | | 123,935 | | 142,490 | | (122,478 | ) | 155,874 | |
|
|
|
|
|
|
|
|
|
|
|
| Current assets | | | | | | | | | | |
| Loans | – | | – | | 165 | | – | | 165 | |
| Inventories | 202 | | – | | 26,352 | | – | | 26,554 | |
| Trade and other receivables | 15,986 | | 840 | | 44,686 | | (23,492 | ) | 38,020 | |
| Derivative financial instruments | – | | – | | 6,321 | | – | | 6,321 | |
| Prepayments | 24 | | – | | 3,565 | | – | | 3,589 | |
| Current tax receivable | – | | – | | 705 | | – | | 705 | |
| Cash and cash equivalents | (10 | ) | 244 | | 3,328 | | – | | 3,562 | |
|
|
|
|
|
|
|
|
|
|
|
| | 16,202 | | 1,084 | | 85,122 | | (23,492 | ) | 78,916 | |
| Assets classified as held for sale | – | | – | | 1,286 | | – | | 1,286 | |
|
|
|
|
|
|
|
|
|
|
|
| | 16,202 | | 1,084 | | 86,408 | | (23,492 | ) | 80,202 | |
|
|
|
|
|
|
|
|
|
|
|
| Total assets | 28,129 | | 125,019 | | 228,898 | | (145,970 | ) | 236,076 | |
|
|
|
|
|
|
|
|
|
|
|
| Current liabilities | | | | | | | | | | |
| Trade and other payables | 5,233 | | 3,115 | | 58,296 | | (23,492 | ) | 43,152 | |
| Derivative financial instruments | – | | – | | 6,405 | | – | | 6,405 | |
| Accruals | – | | 10 | | 6,630 | | – | | 6,640 | |
| Finance debt | 55 | | – | | 15,339 | | – | | 15,394 | |
| Current tax payable | 306 | | – | | 2,976 | | – | | 3,282 | |
| Provisions | – | | – | | 2,195 | | – | | 2,195 | |
|
|
|
|
|
|
|
|
|
|
|
| | 5,594 | | 3,125 | | 91,841 | | (23,492 | ) | 77,068 | |
| Liabilities directly associated with assets classified as held for sale | – | | – | | 163 | | – | | 163 | |
|
|
|
|
|
|
|
|
|
|
|
| | 5,594 | | 3,125 | | 92,004 | | (23,492 | ) | 77,231 | |
|
|
|
|
|
|
|
|
|
|
|
| Non-current liabilities | | | | | | | | | | |
| Other payables | 559 | | 27 | | 4,550 | | (3,885 | ) | 1,251 | |
| Derivative financial instruments | – | | – | | 5,002 | | – | | 5,002 | |
| Accruals | – | | 44 | | 915 | | – | | 959 | |
| Finance debt | – | | – | | 15,651 | | – | | 15,651 | |
| Deferred tax liabilities | 1,765 | | 1,885 | | 15,565 | | – | | 19,215 | |
| Provisions | 946 | | – | | 11,954 | | – | | 12,900 | |
| Defined benefit pension plan and other post-retirement benefit plan deficits | – | | – | | 9,215 | | – | | 9,215 | |
|
|
|
|
|
|
|
|
|
|
|
| | 3,270 | | 1,956 | | 62,852 | | (3,885 | ) | 64,193 | |
|
|
|
|
|
|
|
|
|
|
|
| Total liabilities | 8,864 | | 5,081 | | 154,856 | | (27,377 | ) | 141,424 | |
|
|
|
|
|
|
|
|
|
|
|
| Net assets | 19,265 | | 119,938 | | 74,042 | | (118,593 | ) | 94,652 | |
|
|
|
|
|
|
|
|
|
|
|
| Equity | | | | | | | | | | |
| BP shareholders’ equity | 19,265 | | 119,938 | | 73,080 | | (118,593 | ) | 93,690 | |
| Minority interest | – | | – | | 962 | | – | | 962 | |
|
|
|
|
|
|
|
|
|
|
|
| Total equity | 19,265 | | 119,938 | | 74,042 | | (118,593 | ) | 94,652 | |
|
|
|
|
|
|
|
|
|
|
|
Back to Contents
| | | | | | | | | | | |
| 52 Condensed consolidating information on certain US subsidiaries continued | | | | | | | | | | |
| | | | | | | | | | | |
| 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 | |
|
|
|
|
|
|
|
|
|
|
|
| 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 | ) | – | |
|
|
|
|
|
|
|
|
|
|
|
| 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 | – | | – | | 1,034 | | – | | 1,034 | |
| Defined benefit pension plan surplus | – | | 5,662 | | 1,091 | | – | | 6,753 | |
|
|
|
|
|
|
|
|
|
|
|
| | 10,468 | | 114,577 | | 130,686 | | (113,469 | ) | 142,262 | |
|
|
|
|
|
|
|
|
|
|
|
| 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 | 15 | | – | | 2,991 | | – | | 3,006 | |
| Current tax receivable | – | | – | | 544 | | – | | 544 | |
| Cash and cash equivalents | (5 | ) | (21 | ) | 2,616 | | – | | 2,590 | |
|
|
|
|
|
|
|
|
|
|
|
| | 15,874 | | 3,053 | | 82,876 | | (27,542 | ) | 74,261 | |
| Assets classified as held for sale | – | | – | | 1,078 | | – | | 1,078 | |
|
|
|
|
|
|
|
|
|
|
|
| | 15,874 | | 3,053 | | 83,954 | | (27,542 | ) | 75,339 | |
|
|
|
|
|
|
|
|
|
|
|
| Total assets | 26,342 | | 117,630 | | 214,640 | | (141,011 | ) | 217,601 | |
|
|
|
|
|
|
|
|
|
|
|
| Current liabilities | | | | | | | | | | |
| Trade and other payables | 4,908 | | 5,185 | | 59,685 | | (27,542 | ) | 42,236 | |
| Derivative financial instruments | – | | – | | 9,424 | | – | | 9,424 | |
| Accruals | – | | 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 | – | | 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
| 180 | |
|
| |
| 52 Condensed consolidating information on certain US subsidiaries continued |
| |
| Cash flow statement | | | | | | | | | $ million | |
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | 2007 | |
|
|
|
|
|
|
|
|
|
|
|
| | Issuer | | Guarantor | | | | | | | |
| |
|
|
|
| | | | | | |
| | BP | | | | | | Eliminations | | | |
| | Exploration | | | Other | | and | | | |
| | (Alaska) Inc. | BP p.l.c. | | subsidiaries | | reclassifications | | BP group | |
|
|
|
|
|
|
|
|
|
|
|
| Net cash provided by operating activities | 3,072 | | 15,403 | | 22,839 | | (16,605 | ) | 24,709 | |
| Net cash used in investing activities | (532 | ) | 1 | | (14,306 | ) | – | | (14,837 | ) |
| Net cash used in financing activities | (2,545 | ) | (15,139 | ) | (7,956 | ) | 16,605 | | (9,035 | ) |
| Currency translation differences relating to cash and cash equivalents | – | | – | | 135 | | – | | 135 | |
|
|
|
|
|
|
|
|
|
|
|
| (Decrease) increase in cash and cash equivalents | (5 | ) | 265 | | 712 | | – | | 972 | |
| Cash and cash equivalents at beginning of year | (5 | ) | (21 | ) | 2,616 | | – | | 2,590 | |
|
|
|
|
|
|
|
|
|
|
|
| Cash and cash equivalents at end of year | (10 | ) | 244 | | 3,328 | | – | | 3,562 | |
|
| |
| | | | | | | | | | $ 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 | |
|
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 14.
| | | | | | | | | | | | | | | | | | | 2007 | |
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
| Crude oila | | | | | | | | | | | | | | | million barrels | |
|
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|
|
|
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|
|
|
|
| | | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| UK | Europe | US | Americas | Pacific | Africa | Russia | Other | Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2007 | | | | | | | | | | | | | | | | | | |
| | Developed | 458 | | 189 | | 1,916 | | 130 | | 67 | | 193 | | – | | 88 | | 3,041 | |
| | Undeveloped | 146 | | 97 | | 1,292 | | 237 | | 86 | | 512 | | – | | 482 | | 2,852 | |
| |
| | | 604 | | 286 | | 3,208 | | 367 | | 153 | | 705 | | – | | 570 | | 5,893 | |
|
| Changes attributable to | | | | | | | | | | | | | | | | | | |
| | Revisions of previous estimates | (1 | ) | (25 | ) | 18 | | (29 | ) | (7 | ) | (133 | ) | – | | (27 | ) | (204 | ) |
| | Purchases of reserves-in-place | – | | – | | 25 | | – | | – | | – | | – | | 8 | | 33 | |
| | Discoveries and extensions | – | | 31 | | 60 | | 1 | | 2 | | 93 | | – | | – | | 187 | |
| | Improved recovery | 7 | | 1 | | 99 | | 6 | | 5 | | 12 | | – | | 1 | | 131 | |
| | Productionb | (73 | ) | (19 | ) | (169 | ) | (27 | ) | (15 | ) | (71 | ) | – | | (80 | ) | (454 | ) |
| | Sales of reserves-in-place | – | | – | | (94 | ) | – | | – | | – | | – | | – | | (94 | ) |
| |
| | | (67 | ) | (12 | ) | (61 | ) | (49 | ) | (15 | ) | (99 | ) | – | | (98 | ) | (401 | ) |
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| At 31 December 2007c | | | | | | | | | | | | | | | | | | |
| | Developed | 414 | | 105 | | 1,882 | | 115 | | 61 | | 256 | | – | | 104 | | 2,937 | |
| | Undeveloped | 123 | | 169 | | 1,265 | | 203 | | 77 | | 350 | | – | | 368 | | 2,555 | |
| |
| | | 537 | | 274 | | 3,147 | f | 318 | | 138 | | 606 | | – | | 472 | | 5,492 | |
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| Equity-accounted entities (BP share)d | | | | | | | | | | | | | | | | | | |
| At 1 January 2007 | | | | | | | | | | | | | | | | | | |
| | 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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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| | Revisions of previous estimates | – | | – | | – | | 178 | | – | | – | | 413 | | 167 | | 758 | |
| | Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | 16 | | – | | 16 | |
| | Discoveries and extensions | – | | – | | – | | 2 | | – | | – | | 283 | | – | | 285 | |
| | Improved recovery | – | | – | | – | | 59 | | – | | – | | – | | 1 | | 60 | |
| | Production | – | | – | | – | | (28 | ) | – | | – | | (304 | ) | (73 | ) | (405 | ) |
| | Sales of reserves-in-place | – | | – | | – | | – | | – | | – | | (21 | ) | – | | (21 | ) |
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| | | – | | – | | – | | 211 | | – | | – | | 387 | | 95 | | 693 | |
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| At 31 December 2007e | | | | | | | | | | | | | | | | | | |
| | Developed | – | | – | | – | | 328 | | 1 | | – | | 2,094 | | 573 | | 2,996 | |
| | Undeveloped | – | | – | | – | | 243 | | – | | – | | 1,137 | | 205 | | 1,585 | |
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| | | – | | – | | – | | 571 | | 1 | | – | | 3,231 | | 778 | | 4,581 | |
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| a | Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
| b | Excludes NGLs from processing plants in which an interest is held of 54 thousand barrels a day. |
| c | Includes 739 million barrels of NGLs. Also includes 20 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | The BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. During the second quarter of 2007, we updated our reporting policy in Abu Dhabi to be consistent with general industry practice and as a result have started reporting production and reserves there gross of production taxes. This change resulted in an increase in our reserves of 153 million barrels and in our production of 33mb/d. |
| e | Includes 26 million barrels of NGLs. Also includes 210 million barrels of crude oil in respect of the 6.51% minority interest in TNK-BP. |
| f | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 98 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 | | | | | | | | | | | | | | | | | 2007 | |
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| Natural gasa | | | | | | | | | | | | | | | billion cubic feet | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | UK | | Europe | | US | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
| At 1 January 2007 | | | | | | | | | | | | | | | | | | |
| 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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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | 93 | | (37 | ) | 744 | | (276 | ) | 140 | | (146 | ) | – | | (21 | ) | 497 | |
| Purchases of reserves-in-place | – | | – | | 23 | | – | | – | | – | | – | | 109 | | 132 | |
| Discoveries and extensions | – | | 293 | | 95 | | 249 | | 88 | | 17 | | – | | – | | 742 | |
| Improved recovery | 15 | | 1 | | 326 | | 32 | | 111 | | 9 | | – | | 5 | | 499 | |
| Productionb | (299 | ) | (14 | ) | (879 | ) | (1,047 | ) | (261 | ) | (187 | ) | – | | (114 | ) | (2,801 | ) |
| Sales of reserves-in-place | – | | (68 | ) | (32 | ) | (7 | ) | – | | – | | – | | – | | (107 | ) |
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| | (191 | ) | 175 | | 277 | | (1,049 | ) | 78 | | (307 | ) | – | | (21 | ) | (1,038 | ) |
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| At 31 December 2007c | | | | | | | | | | | | | | | | | | |
| Developed | 2,049 | | 63 | | 10,670 | | 3,683 | | 1,822 | | 990 | | – | | 583 | | 19,860 | |
| Undeveloped | 553 | | 410 | | 4,705 | | 8,394 | | 4,817 | | 1,410 | | – | | 981 | | 21,270 | |
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| | 2,602 | | 473 | | 15,375 | | 12,077 | | 6,639 | | 2,400 | | – | | 1,564 | | 41,130 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
| At 1 January 2007 | | | | | | | | | | | | | | | | | | |
| 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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| Changes attributable to | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | – | | – | | – | | 73 | | (2 | ) | – | | 61 | | 11 | | 143 | |
| Purchases of reserves-in-place | – | | – | | – | | – | | – | | – | | 8 | | – | | 8 | |
| Discoveries and extensions | – | | – | | – | | 22 | | – | | – | | – | | – | | 22 | |
| Improved recovery | – | | – | | – | | 195 | | 16 | | – | | – | | – | | 211 | |
| Productionb | – | | – | | – | | (176 | ) | (13 | ) | – | | (179 | ) | (9 | ) | (377 | ) |
| Sales of reserves-in-place | – | | – | | – | | – | | – | | – | | – | | – | | – | |
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| | – | | – | | – | | 114 | | 1 | | – | | (110 | ) | 2 | | 7 | |
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| At 31 December 2007d | | | | | | | | | | | | | | | | | | |
| Developed | – | | – | | – | | 1,478 | | 39 | | – | | 808 | | 148 | | 2,473 | |
| Undeveloped | – | | – | | – | | 831 | | 37 | | – | | 353 | | 76 | | 1,297 | |
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| | – | | – | | – | | 2,309 | | 76 | | – | | 1,161 | | 224 | | 3,770 | |
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| a | Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royally owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
| b | Includes 202 billion cubic feet of natural gas consumed in operations, 161 billion cubic feet in subsidiaries, 41 billion cubic feet in equity-accounted entities and excludes 10.9 billion cubic feet of produced non-hydrocarbon components which meet regulatory requirements for sales. |
| c | Includes 3,211 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
| d | Includes 68 billion cubic feet of natural gas in respect of the 5.88% minority interest in TNK-BP. |
Back to Contents
Supplementary information on oil and natural gas (unaudited) continued
| Movements in estimated net proved reserves | | | | | | | | | | | | | | | | | 2006 | |
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| Crude oila | | | | | | | | | | | | | | | million barrels | |
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| | | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
| | | UK | | Europe | | US | | 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 | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| | Discoveries and extensions | 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 | |
| | Discoveries and extensions | – | | – | | – | | 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. Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option to make lifting and sales arrangements independently. |
| 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 | | US | | 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 | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| | Discoveries and extensions | 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 | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| | Discoveries and extensions | – | | – | | – | | 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 | Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option to make lifting and sales arrangements independently. |
| 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
| Movement 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 | | US | | 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 | |
| Discoveries and extensions | 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 | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Discoveries and extensions | – | | – | | – | | 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. Proved reserves exclude royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option to make lifting and sales arrangements independently. |
| 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
| Movement 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 | | US | | 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 | |
| Discoveries and extensions | 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 | – | | – | | – | | – | | – | | – | | – | | – | | – | |
| Discoveries and extensions | – | | – | | – | | 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 | Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option to make lifting and sales arrangements independently. |
| 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
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.
| | | | | | | | | | | | | | | | $ million | |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | |
| | UK | | Europe | | US | | Americas | | Pacific | | Africa | | Other | | Total | |
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| At 31 December 2007 | | | | | | | | | | | | | | | | |
| Future cash inflowsa | 72,100 | | 29,500 | | 350,100 | | 67,700 | | 47,600 | | 63,300 | | 49,400 | | 679,700 | |
| Future production costb | 27,500 | | 7,500 | | 109,800 | | 17,900 | | 12,800 | | 9,900 | | 8,500 | | 193,900 | |
| Future development costb | 4,000 | | 3,300 | | 21,900 | | 6,500 | | 4,100 | | 8,300 | | 3,500 | | 51,600 | |
| Future taxationc | 20,200 | | 13,000 | | 71,600 | | 21,700 | | 9,700 | | 17,100 | | 8,700 | | 162,000 | |
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| Future net cash flows | 20,400 | | 5,700 | | 146,800 | | 21,600 | | 21,000 | | 28,000 | | 28,700 | | 272,200 | |
| 10% annual discountd | 6,500 | | 2,800 | | 76,000 | | 9,500 | | 10,300 | | 9,400 | | 11,500 | | 126,000 | |
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| Standardized measure of discounted future net cash flowse | 13,900 | | 2,900 | | 70,800 | | 12,100 | | 10,700 | | 18,600 | | 17,200 | | 146,200 | |
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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 future net 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 future net cash flowse | 18,200 | | 2,100 | | 60,700 | | 14,700 | | 7,300 | | 13,100 | | 12,100 | | 128,200 | |
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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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| | 2007 | | 2006 | | 2005 | |
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| Sales and transfers of oil and gas produced, net of production costs | (28,300 | ) | (35,800 | ) | (24,300 | ) |
| Development costs incurred during the year | 9,400 | | 8,200 | | 7,100 | |
| Extensions, discoveries and improved recovery, less related costs | 12,300 | | 7,900 | | 10,100 | |
| Net changes in prices and production cost | 102,100 | | (43,900 | ) | 84,200 | |
| Revisions of previous reserves estimates | (12,200 | ) | (9,500 | ) | (17,400 | ) |
| Net change in taxation | (28,300 | ) | 32,200 | | (20,500 | ) |
| Future development costs | (7,800 | ) | (7,000 | ) | (5,800 | ) |
| Net change in purchase and sales of reserves-in-place | (700 | ) | (2,500 | ) | (2,500 | ) |
| Addition of 10% annual discount | 9,100 | | 12,800 | | 8,800 | |
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| Total change in the standardized measure during the yearf | 55,600 | | (37,600 | ) | 39,700 | |
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| a | The year-end marker prices used were Brent $96.02/bbl, Henry Hub $7.10/mmBtu (2006 Brent $58.93/bbl, Henry Hub $5.52/mmBtu; 2005 Brent $58.21/bbl, Henry Hub $9.52/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 $2,300 million at 31 December 2007 ($1,300 million at 31 December 2006 and $2,700 million at 31 December 2005). |
| f | Total change in the standardized measure during the year includes the effect of exchange rate movements. |
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Supplementary information on oil and natural gas (unaudited) continued
Equity-accounted entities
In addition, at 31 December 2007, the group’s share of the standardized measure of discounted future net cash flows of equity-accounted entities amounted to $28,300 million ($14,700 million at 31 December 2006 and $19,300 million at 31 December 2005).
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 2007, 2006 and 2005.
| Production for the yeara |
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| | | | Rest of | | | | Rest of | | Asia | | | | | | | | | |
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| Subsidiaries | | | | | | | | | | | | | | | | | | |
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| Crude oilb | | | | | | | | | | | | | | thousand barrels per day | |
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| 2007 | 201 | | 51 | | 513 | | 82 | | 41 | | 195 | | – | | 221 | | 1,304 | |
| 2006 | 253 | | 61 | | 547 | | 108 | | 44 | | 177 | | – | | 161 | | 1,351 | |
| 2005 | 277 | | 75 | | 612 | | 144 | | 47 | | 175 | | – | | 93 | | 1,423 | |
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| Natural gasc | | | | | | | | | | | | | | million cubic feet per day | |
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| 2007 | 768 | | 29 | | 2,174 | | 2,798 | | 699 | | 468 | | – | | 286 | | 7,222 | |
| 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 | |
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| Equity-accounted entities (BP share) | | | | | | | | | | | | | | | | | | |
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| Crude oilb | | | | | | | | | | | | | | thousand barrels per day | |
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| 2007 | – | | – | | – | | 77 | | 1 | | – | | 832 | | 200 | | 1,110 | |
| 2006 | – | | – | | – | | 77 | | 1 | | – | | 876 | | 170 | | 1,124 | |
| 2005 | – | | – | | – | | 71 | | – | | – | | 911 | | 157 | | 1,139 | |
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| Natural gasc | | | | | | | | | | | | | | million cubic feet per day | |
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| 2007 | – | | – | | – | | 429 | | 33 | | – | | 451 | | 8 | | 921 | |
| 2006 | – | | – | | – | | 416 | | 37 | | – | | 544 | | 8 | | 1,005 | |
| 2005 | – | | – | | – | | 375 | | 47 | | – | | 482 | | 8 | | 912 | |
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| a | Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
| 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 2007. 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 | | US | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Number of productive wells at 31 December 2007 | | | | | | | | | | | | | | | | | | |
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| Oil wellsa | – gross | 274 | | 81 | | 5,885 | | 3,524 | | 352 | | 646 | | 19,393 | | 1,536 | | 31,691 | |
| | – net | 147 | | 26 | | 2,093 | | 1,925 | | 152 | | 538 | | 8,252 | | 255 | | 13,388 | |
| Gas wellsb | – gross | 303 | | – | | 18,173 | | 2,274 | | 681 | | 90 | | 47 | | 131 | | 21,699 | |
| | – net | 140 | | – | | 11,462 | | 1,383 | | 249 | | 42 | | 23 | | 88 | | 13,387 | |
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| a | Includes approximately 1,016 gross (289 net) multiple completion wells (more than one formation producing into the same well bore). |
| b | Includes approximately 2,489 gross (1,591 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 | | US | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| Oil and natural gas acreage at 31 December 2007 | | | | | | | | | | | | | | | Thousands of acres | |
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| Developed | – gross | 428 | | 143 | | 7,414 | | 2,793 | | 1,235 | | 541 | | 4,071 | | 1,870 | | 18,495 | |
| | – net | 201 | | 34 | | 4,742 | | 1,310 | | 319 | | 225 | | 1,768 | | 690 | | 9,289 | |
| Undevelopeda | – gross | 1,696 | | 505 | | 6,451 | | 11,529 | | 7,450 | | 15,759 | | 13,821 | | 14,412 | | 71,623 | |
| | – net | 967 | | 227 | | 4,574 | | 5,912 | | 2,782 | | 9,755 | | 5,777 | | 5,969 | | 35,963 | |
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| a | Undeveloped acreage includes leases and concessions. |
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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 | | US | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| 2007 | | | | | | | | | | | | | | | | | | |
| Exploratory | | | | | | | | | | | | | | | | | | |
| Productive | 1.6 | | – | | 4.1 | | 0.5 | | 1.1 | | 6.1 | | 16.0 | | 1.7 | | 31.1 | |
| Dry | – | | – | | 0.7 | | 0.5 | | 0.4 | | 1.6 | | 9.0 | | 1.0 | | 13.2 | |
| Development | | | | | | | | | | | | | | | | | | |
| Productive | 0.4 | | 0.8 | | 401.2 | | 46.0 | | 13.8 | | 15.3 | | 246.0 | | 15.8 | | 739.3 | |
| Dry | 0.6 | | – | | 4.2 | | 8.8 | | – | | – | | 9.5 | | – | | 23.1 | |
| 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 | |
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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 2007. 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 | | US | | Americas | | Pacific | | Africa | | Russia | | Other | | Total | |
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| At 31 December 2007 | | | | | | | | | | | | | | | | | | |
| Exploratory | | | | | | | | | | | | | | | | | | |
| Gross | – | | 1 | | 26 | | 5 | | 1 | | 3 | | 28 | | 2 | | 66 | |
| Net | – | | 0.5 | | 12.1 | | 1.9 | | 0.2 | | 1.3 | | 13.5 | | 0.5 | | 30.0 | |
| Development | | | | | | | | | | | | | | | | | | |
| Gross | 6 | | 2 | | 258 | | 39 | | 12 | | 25 | | 30 | | 9 | | 381 | |
| Net | 2.5 | | 0.5 | | 130.5 | | 23.1 | | 5.0 | | 8.9 | | 12.5 | | 2.7 | | 185.7 | |
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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: 4 March 2008
