Notes to the Group financial statements 1 – 10

Year ended 31 December 2010

• Note 1: Segmental reporting
• Note 2: Total revenue
• Note 3: Operating profit
• Note 4: Staff costs
• Note 5: Finance costs
• Note 6: Taxation on profit on ordinary activities
• Note 7: Dividends
• Note 8: Earnings per ordinary share
• Note 9: Intangible exploration and evaluation assets
• Note 10: Property, plant and equipment

Note 1. Segmental reporting

In the opinion of the Directors, the operations of the Group comprise one class of business, oil and gas exploration, development and production and the sale of hydrocarbons and related activities. The Group also operates within four geographical markets Africa, Europe, South Asia and South America.

The following tables present revenue, profit and certain asset and liability information regarding the Group’s business segments. All sales are to external customers.

Included in revenue arising from Africa are revenues of approximately $546.1 million (2009: $269.2 million, 2008: $484.5 million) which arose from sales to the Group’s largest customers.

Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a geographic area. The liabilities comprise the Group’s external debt and other non-attributable corporate liabilities.

Note 2. Total revenue

Note 3. Operating profit

All assurance and other non-audit services are in compliance with UK ethical standards on independence and the Group’s non-audit services policy. The level of such fees reflects a period of significant expansion for the Group.

Taxation services include tax compliance services and assistance in connection with enquiries from local fiscal authorities. Information technology services includes IT security analysis and assistance provided to management in the selection of new systems. The auditors are not involved in the design or implementation of IT systems.

Other non-assurance services include assistance to management in assessing changes to the finance function resulting from the Group’s expansion, and subscription fees for upstream data.

Note 4. Staff costs

The average monthly number of employees (including Executive Directors) employed by the Group worldwide was:

Staff costs in respect of those employees were as follows:

A proportion of the Group’s staff costs shown above is recharged to the Group’s joint venture partners and a proportion is capitalised into the cost of fixed assets under the Group’s accounting policy for exploration, evaluation and production assets. The net staff costs recognised in the income statement were $55.4 million (2009: $36.3 million).

Details of Directors’ remuneration, Directors’ transactions and Directors’ interests are set out in the part of the Directors’ remuneration report described as having been audited which forms part of these financial statements.

Note 5. Finance costs

Borrowing costs included in the cost of qualifying assets during the year arose on the general borrowing pool and are calculated by applying a capitalisation rate of 4.51% (2009: 3.89%) to cumulative expenditure on such assets.

Note 6. Taxation on profit on ordinary activities

(a) Analysis of charge in period

The tax charge comprises:

(b) Factors affecting tax charge for period

The tax rate applied to profit on ordinary activities in preparing the reconciliation below is the upstream UK corporation tax applicable to the Group’s oil and gas activities plus the rate of Supplementary corporation tax (SCT).

The difference between the total current tax charge shown above and the amount calculated by applying the standard rate of UK corporation tax applicable to UK profits derived from upstream activities (30%) plus the rate of SCT in respect of UK upstream profits (20%) to the profit before tax is as follows:

The Group’s profit before taxation will continue to be subject to jurisdictions where the effective rate of taxation differs from that in the UK. Furthermore, unsuccessful exploration expenditure is often incurred in jurisdictions where the Group has no taxable profits, such that no related tax benefit arises. Accordingly, the Group’s tax charge will continue to depend on the jurisdictions in which pre-tax profits and exploration costs written off arise.

The Group has tax losses of $840.1 million (2009: $412.3 million) that are available indefinitely for offset against future taxable profits in the companies in which the losses arose. Deferred tax assets have not been recognised in respect of these losses as they may not be used to offset taxable profits elsewhere in the Group.

The Group has recognised $184.0 million in deferred tax assets in relation to taxable losses (2009: $38.9 million).

No deferred tax liability is recognised on temporary differences of $485.6 million (2009: $433.8 million) relating to unremitted earnings of overseas subsidiaries as the Group is able to control the timing of the reversal of these temporary differences and it is probable that they will not reverse in the foreseeable future.

Note 7. Dividends

The proposed final dividend is subject to approval by shareholders at the Annual General Meeting and has not been included as a liability in these financial statements.

Note 8. Earnings per ordinary share

Basic earnings per ordinary share amounts are calculated by dividing net profit for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year.

Diluted earnings per ordinary share amounts are calculated by dividing net profit for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued if employee and other share options were converted into ordinary shares.

Note 9. Intangible exploration and evaluation assets

The amounts for intangible exploration and evaluation assets represent active exploration projects. These amounts will be written off to the income statement as exploration costs unless commercial reserves are established or the determination process is not completed and there are no indications of impairment. The outcome of ongoing exploration, and therefore whether the carrying value of exploration and evaluation assets will ultimately be recovered, is inherently uncertain.

Additions include $1,450 million in relation to the acquisition of a 50% stake in Blocks 1 and 3A in Uganda (2009: $nil, 2008: $nil) and capitalised interest of $30.7 million (2009: $17.5 million, 2008: $nil million). The Group only capitalises interest in respect of intangible exploration and evaluation assets where it is considered that development is highly likely and advanced appraisal and development is ongoing.

In 2008 amounts written off included an impairment charge calculated in accordance with IAS 36 – Impairment of Assets – of $111.5 million, determined by estimating value in use. The impairment resulted from lower reserves estimates following a change in the most likely development plans and lower assumed oil prices following the fall in oil prices in the second half of 2008. In calculating this impairment, management used a range of assumptions, including a long-term oil price of $80 per barrel and a 15% pre-tax discount rate.

Note 10. Property, plant and equipment

Additions include capitalised interest of $47.4 million (2009: $22.8 million, 2008: $11.4 million).

The carrying amount of the Group’s oil and gas assets includes an amount of $346.7 million (2009: $13.5 million, 2008: $14.1 million) in respect of assets held under finance leases.

Other fixed assets include leasehold improvements, motor vehicles and office equipment.

The 2010 impairment loss relates to the Chinguetti field in Mauritania (2009: Chinguetti field in Mauritania, 2008: Chinguetti field in Mauritania). The recoverable amount was determined by estimating its value in use. In calculating this impairment, management used a production profile based on proven and probable reserves estimates and a range of assumptions, including an oil price assumption equal to the forward curve in 2011 and 2012 and $80 per barrel thereafter and a pre-tax discount rate assumption of 15%.

Depletion and amortisation for oil and gas properties is calculated on a unit-of-production basis, using the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus production in the period, generally on a field-by-field basis. Commercial reserves estimates are based on a number of underlying assumptions including oil and gas prices, future costs, oil and gas in place and reservoir performance, which are inherently uncertain. Commercial reserves estimates are based on a Group reserves report produced by an independent engineer. However, the amount of reserves that will ultimately be recovered from any field cannot be known with certainty until the end of the field’s life.