• 2.35 Mboe/d of hydrocarbons produced in 2011
• 11.4 Bboe of proved reserves as of December 31, 2011⁽¹⁾
• Capital expenditure for 2011: €21.7 billion
• 23,563 employees

For the full year 2011, adjusted net operating income from the Upstream segment was €10,405 million compared to €8,597 million in 2010, an increase of 21%. Expressed in dollars, adjusted net operating income from the Upstream segment was $14.5 billion, an increase of 27% compared to 2010, essentially due to the impact of higher hydrocarbon prices.

Technical costs(2) for consolidated subsidiaries, in accordance with ASC 932(3), were 18.9 $/boe(4) in 2011, compared to 16.6 $/boe in 2010. The return on average capital employed (ROACE(5)) for the Upstream segment was 20%, for the full-year 2011 compared to 21% for the full year 2010.
TOTAL’s average liquids price increased by 38% in 2011 compared to 2010 and TOTAL’s average gas price increased by 27% compared to 2010.

For the full-year 2011, hydrocarbon production was 2,346 kboe/d, a decrease of 1.3% compared to 2010, essentially as a result of:

• -1.5% for normal decline, net of production ramp-ups on new projects;
• +2.5% for changes in the portfolio, integrating the net share of Novatek production and impact of the sale of interests in CEPSA,
• +1% for the end of OPEC reductions;
• -1.5% for security conditions, mainly in Libya;
• -2% for the price effect(6).

Proved reserves based on SEC rules (based on Brent at 110.96 $/b) were 11,423 Mboe at December 31, 2011. Based on the 2011 average rate of production, the reserve life is 13 years.
The 2011 proved reserve replacement rate(7), based on SEC rules, was 185%. As of year-end 2011, Total has a solid and diversified portfolio of proved and probable reserves(8) representing more than 20 years of reserve life based on the 2011 average production rate, and resources(9) representing more than 40 years of reserve life.

(1) Based on a Brent crude price of $110.96/b.
(2) (Production costs + exploration expenses + depreciation, depletion and amortization and valuation allowances)/production of the year.
(3) FASB Accounting Standards Codification Topic 932, Extractive industries – Oil and Gas.
(4) Excluding IAS 36 (impairment of assets).
(5) Calculated based on adjusted net operating income and average capital employed, using replacement cost.
(6) Impact of changing hydrocarbon prices on entitlement volumes.
(7) Change in reserves excluding production i.e. (revisions + discoveries, extensions + acquisitions – divestments) / production for the period. The reserve replacement rate would be 84% in an environment with a constant 79.02 $/b oil price, excluding acquisitions and divestments.
(8) Limited to proved and probable reserves covered by E&P contracts on fields that have been drilled and for which technical studies have demonstrated economic development in a 100 $/b Brent environment, including projects developed by mining.
(9) Proved and probable reserves plus contingent resources (potential average recoverable reserves from known accumulations - Society of Petroleum Engineers - 03/07).