10 288 Supplemental oil and gas information (unaudited) Oil and gas information pursuant to FASB Accounting Standards Codification 932 1.7. Capitalized costs related to oil and gas producing activities The following tables do not include capitalized costs related to oil and gas transportation and LNG liquefaction and transportation activities. (M€) Consolidated subsidiaries As of December 31, 2009 Proved properties 30,613 27,557 7,123 5,148 10,102 80,543 Unproved properties 337 1,138 839 30 555 2,899 <strong>Total</strong> capitalized costs 30,950 28,695 7,962 5,178 10,657 83,442 Accumulated depreciation, depletion and amortization (21,870) (13,510) (2,214) (3,325) (3,085) (44,004) Net capitalized costs 9,080 15,185 5,748 1,853 7,572 39,438 As of December 31, 2010 Proved properties 31,735 32,494 7,588 5,715 12,750 90,282 Unproved properties 402 1,458 2,142 49 1,433 5,484 <strong>Total</strong> capitalized costs 32,137 33,952 9,730 5,764 14,183 95,766 Accumulated depreciation, depletion and amortization (23,006) (16,716) (2,302) (3,849) (4,092) (49,965) Net capitalized costs 9,131 17,236 7,428 1,915 10,091 45,801 As of December 31, <strong>2011</strong> Proved properties 34,308 37,032 8,812 6,229 17,079 103,460 Unproved properties 460 1,962 4,179 62 911 7,574 <strong>Total</strong> capitalized costs 34,768 38,994 12,991 6,291 17,990 111,034 Accumulated depreciation, depletion and amortization (24,047) (18,642) (2,294) (4,274) (5,066) (54,323) Net capitalized costs 10,721 20,352 10,697 2,017 12,924 56,711 As of December 31, 2009 Proved properties - 610 726 2,404 - 3,740 Unproved properties - - 135 - 62 197 <strong>Total</strong> capitalized costs - 610 861 2,404 62 3,937 Accumulated depreciation, depletion and amortization - (387) (171) (1,723) - (2,281) Net capitalized costs - 223 690 681 62 1,656 As of December 31, 2010 Proved properties - 639 887 3,110 - 4,636 Unproved properties - 25 168 - 138 331 <strong>Total</strong> capitalized costs - 664 1,055 3,110 138 4,967 Accumulated depreciation, depletion and amortization - (462) (307) (2,029) - (2,798) Net capitalized costs - 202 748 1,081 138 2,169 As of December 31, <strong>2011</strong> Europe Africa Americas Middle East Asia <strong>Total</strong> (M€) Equity affiliates Europe Africa Americas Middle East Asia <strong>Total</strong> Proved properties - - 731 3,496 3,973 8,200 Unproved properties - - - - 1,146 1,146 <strong>Total</strong> capitalized costs - - 731 3,496 5,119 9,346 Accumulated depreciation, depletion and amortization - - (96) (2,337) (213) (2,646) Net capitalized costs - - 635 1,159 4,906 6,700 TOTAL. <strong>Registration</strong> Document <strong>2011</strong>
The standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities was developed as follows: – estimates of proved reserves and the corresponding production profiles are based on existing technical and economic conditions; – the estimated future cash flows are determined based on prices used in estimating the Group’s proved oil and gas reserves; – the future cash flows incorporate estimated production costs (including production taxes), future development costs and asset retirement costs. All cost estimates are based on year-end technical and economic conditions; (M€) Consolidated subsidiaries As of December 31, 2009 Future cash inflows 50,580 107,679 18,804 9,013 32,004 218,080 Future production costs (11,373) (23,253) (8,286) (2,831) (6,996) (52,739) Future development costs (12,795) (21,375) (5,728) (698) (6,572) (47,168) Future in<strong>com</strong>e taxes (17,126) (36,286) (1,293) (2,041) (5,325) (62,071) Future net cash flows, after in<strong>com</strong>e taxes 9,286 26,765 3,497 3,443 13,111 56,102 Discount at 10% (3,939) (13,882) (2,696) (1,558) (8,225) (30,300) Standardized measure of discounted future net cash flows 5,347 12,883 801 1,885 4,886 25,802 As of December 31, 2010 Future cash inflows 65,644 142,085 42,378 14,777 41,075 305,959 Future production costs (16,143) (29,479) (19,477) (4,110) (6,476) (75,685) Future development costs (18,744) (25,587) (8,317) (3,788) (8,334) (64,770) Future in<strong>com</strong>e taxes (20,571) (51,390) (3,217) (2,541) (7,281) (85,000) Future net cash flows, after in<strong>com</strong>e taxes 10,186 35,629 11,367 4,338 18,984 80,504 Discount at 10% (5,182) (16,722) (8,667) (2,106) (11,794) (44,471) Standardized measure of discounted future net cash flows 5,004 18,907 2,700 2,232 7,190 36,033 As of December 31, <strong>2011</strong> Future cash inflows 85,919 167,367 53,578 14,297 67,868 389,029 Future production costs (18,787) (31,741) (22,713) (3,962) (12,646) (89,849) Future development costs (21,631) (22,776) (11,548) (3,110) (11,044) (70,109) Future in<strong>com</strong>e taxes (28,075) (71,049) (4,361) (2,794) (12,963) (119,242) Future net cash flows, after in<strong>com</strong>e taxes 17,426 41,801 14,956 4,431 31,215 109,829 Discount at 10% (9,426) (17,789) (12,298) (2,186) (20,717) (62,416) Standardized measure of discounted future net cash flows 8,000 24,012 2,658 2,245 10,498 47,413 Minority interests in future net cash flows as of (M€) Supplemental oil and gas information (unaudited) 10 Oil and gas information pursuant to FASB Accounting Standards Codification 932 1.8. Standardized measure of discounted future net cash flows (excluding transportation) – future in<strong>com</strong>e taxes are <strong>com</strong>puted by applying the year-end statutory tax rate to future net cash flows after consideration of permanent differences and future in<strong>com</strong>e tax credits; and – future net cash flows are discounted at a standard discount rate of 10 percent. These principles applied are those required by ASC 932 and do not reflect the expectations of real revenues from these reserves, nor their present value; hence, they do not constitute criteria for investment decisions. An estimate of the fair value of reserves should also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserves estimates. Europe Africa Americas Middle East Asia <strong>Total</strong> December 31, 2009 212 60 - - - 272 December 31, 2010 273 344 - - - 617 December 31, <strong>2011</strong> - 558 - - - 558 <strong>Registration</strong> Document <strong>2011</strong>. TOTAL 289
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Registration Document 2011
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Registration Document 2011 This tra
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Key figures 1. Operating and market
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Sales Adjusted net income (Group sh
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Shareholder base Estimates as of No
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Business overview Business overview
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2. Upstream TOTAL’s Upstream segm
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As of December 31, 2009, TOTAL’s
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2.3. Presentation of production act
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Indonesia 1968 Myanmar 1992 Thailan
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United Kingdom 1962 Middle East U.A
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In Kenya, TOTAL acquired in Septemb
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In the United States, the Group’s
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The next two wells, which were expl
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is expected to be transported to Ru
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- In addition to Alwyn and the Cent
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2.6. Number of net oil and gas well
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Asia Yadana Yadana (Myanmar) Ban-I
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2.9.3. Marketing To unlock value fr
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As of January 2012, TOTAL owns 66%
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3. Downstream The Downstream segmen
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The heavy conversion process of thi
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In Northern, Central and Eastern Eu
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The oil markets had ended 2010 sign
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4.1. Base Chemicals The Base Chemic
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4.1.2. Fertilizers Through its Fren
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5. Investments 5.1. Major investmen
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7. Property, plant and equipment TO
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Finance Refining & Marketing Financ
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Crude Oil Trading Finance Trading &
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Management Report The Management re
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- a Refining & Chemicals segment, a
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1.2.4. Investments - divestments In
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1.6. TOTAL S.A. 2011 results Net in
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2.5. Anticipated sources of financi
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3.6. Environment Environmental issu
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Risk factors Risk factors 4 1. Fina
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Trading & Shipping : value-at-risk
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1.8. Sensitivity analysis on intere
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1.10. Liquidity risk TOTAL S.A. has
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Customer receivables are subject to
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2.2. Management and monitoring of i
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egions, causing substantial decline
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3.4. Activities in Cuba, Iran, Suda
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and service contracts. In 2011, TOT
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4.3. Insurance policy The Group has
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Corporate governance Corporate gove
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Chairman of the Nominating & Govern
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- Permanent representative of Colam
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du Territoire et de l’Action Rég
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- Director of Europalia Internation
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- monitoring the quality of the inf
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6. COMMITTEES OF THE BOARD OF DIREC
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1.5.2. Compensation Committee Rules
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The term of office of the members o
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- examination of ethical issues (co
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1.8. Director independence At its m
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With regard to counterparty risks,
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Variable compensation is determined
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3. General Management 3.1. Manageme
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4.4. Fees received by the statutory
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total gross compensation as Chairma
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Chairman and Chief Executive Office
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The acquisition rate: - is equal to
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5.7.3. Directors’ fees and other
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5.8. TOTAL stock option grants Corp
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If all the outstanding stock option
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Corporate governance 5 Compensation
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The grant of these performance shar
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6. Employees, share ownership 6.1.
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6.3.1. Summary of transactions in t
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TOTAL and its shareholders TOTAL an
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1.2. Share performance TOTAL share
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1.2.7. TOTAL share price over the p
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2.2. Dividend payment BNP Paribas S
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the Board of Directors decided on J
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- delivered to the holders of secur
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4.4. Major shareholders 4.4.1. Chan
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4.6. Shares held by members of the
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However, there are certain exceptio
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6.4. Registered shareholding TOTAL
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Financial information Financial inf
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4. Dividend policy The Company’s
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criminal chamber of the Court of Ap
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In October 2010, the Prosecutor’s
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General information General informa
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delegations of authority granted by
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1.4. Potential share capital as of
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2.3. Provisions of the by-laws gove
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2.6. Shareholders’ meetings 2.6.1
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In 2011, TOTAL’s holdings in Sano
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Consolidated Financial Statements T
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2. Consolidated statement of income
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4. Consolidated balance sheet TOTAL
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6. Consolidated statement of change
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Non-monetary contributions by ventu
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Intangible assets are carried at co
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when market data are not directly a
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- In June 2011, the IASB issued rev
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Since the acquisition date, sales a
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4) Business segment information Fin
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For the year ended December 31, 201
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For the year ended December 31, 201
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For the year ended December 31, 200
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For the year ended December 31, 201
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Adjustments to net income, Group sh
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7) Other income and other expense F
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The net deferred tax variation in t
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11) Property, plant and equipment C
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12) Equity affiliates: investments
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In Group share, the main financial
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15) Inventories As of December 31,
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17) Shareholders’ equity Number o
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As of December 31, 2011, paid-in su
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The experience actuarial (gains) lo
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19) Provisions and other non-curren
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20) Financial debt and related fina
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Bonds after fair value hedge (M€)
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Bonds after cash flow hedge and fix
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C) Net-debt-to-equity ratio For its
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- Page 247 and 248: condition. This condition states th
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- Page 273 and 274: e paid to those affected by the pol
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4.3. TOTAL and new energies Althoug
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The selected sites and subsidiaries
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Assurance Opinion Completeness of d
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Glossary A Acreage Areas in which m
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MTO/OCP MTO (Methanols to Olefins)
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Cross reference lists Registration
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17. Employees 17.1. Number of emplo
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Registration Document concordance t
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PEFC/10-31-2043 This brochure is pr